&EPA
United States
Environmental Protection
Agency
Policy, Planning,
And Evaluation
(PM-221)
21P-2005
August 1990
Preliminary Technology Cost
Estimates Of Measures
Available To Reduce U.S.
Greenhouse Gas Emissions
By 2010
Report To The U.S. Environmental Protection Aqencv
Office Of Policy Analysis
Printed on Recycled Paper
-------
Estimates!®
Emissions W 2010
Submitted to:
U.S. Environmental Protection Agency
August 1990
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TABLE OF CONTENTS
Page
INTRODUCI1ON AND SUMMARY OF RESULTS . 1
DESCRIPTION OF THE PROJECT .. 1
Overall Results 1
Methodology Used in the Study 2
SUMMARY OF RESULTS 7
L DOCUMENTATION OF ENERGY MEASURES TO REDUCE CO 2 .... 17
Energy Use Baseline and CO 2 Reduction Cases 17
Vehicle Energy Conservation Measures 17
Ethanol Use in Vehicles
Aircraft Energy Conservation 23
Residential/Commercial Energy Conservation 24
Fuel Substitution
Incremental Gas Supply 27
Renewable Electric Technologies 28
Industrial Cogeneration 32
Industrial Heat Pumps 36
Variable Speed Motor Drives 38
IL DOCUMENTATION OF NON-ENERGY GREENHOUSE GAS
EMISSION REDUC11ON STRATEGIES 39
Reforestation of Marginal Ciop and Pasture Land and Unstocked Forests 39
Costs of Phasing Out CFCs 40
Methane Recovery from Municipal Landfills 43
Coal Bed Methane Recovery 45
Methane Recovery from Animal Manure 46
SPTPCI’ED REFERENCES
ATTACHMENT A: Data Developed to Prepare Energy Component of
CO 2 Reduction Cost Curve
ATTACHMENT B: ACEEE Report on Light Duty Vehicles and Trucks
ATFACHMENT C: ICF Analysis of Vehicle Savings Issues
ATTACHMENT D: Memo from Michael Kavanaugh on UDF Aircraft Engine
AT1’ACHMENT E: LBL Report on Residential and Commercial Conservation
ATTACHMENT F: Reforestation Analysis
ATTACHMENT G: CFC Phase Out Analysis
ATTACHMENT H: CO 2 Reduction Cost
ATIACHMENT I: Renewable Energy Background Information
06W0658A
Page I
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INTRODUCTION AND SUMMARY RESULTS
This report provides a summary description of a preliminary set of CO 2 reduction cost curves
developed for the Environmental Protection Agency, documentation for the steps in the cost curve,
and a candid description of the problems with the estimates. Overall, we think the results are
plausible, but some of the individual elements could be criticized for lacking sufficient analytic
support. Additionally, as discussed below, the feasibility and cost of some of the options are
controversial and subject to a number of limitations.
DESCRIPTION OF Th PROJECT
The purpose of this project was to collect available information on the costs of reducing
emissions of CO 2 and other greenhouse gases. The overall methodology included the projection of
CO 2 and C0 2 -equivalent emissions out to 2010, the identification of technologies and programs that
could significantly reduce these emissions, and the estimation of the CO 2 reduction potential and the
associated unit costs for these technologies and programs.
The intent of the study was to quickly gather together available information to develop a set
of cost estimates for. relatively low-cost CO 2 reduction options that would provide an initial scoping
analysis of a wide range of options. This effort is intended to serve as one initial step to support
later, more detailed studies. The focus was on adjusting estimates performed elsewhere for
consistency with a set of specified study assumptions. Subsequently, as serious problems were
identified with existing estimates, or if no estimates could be found, some costs were developed by
ICF and others specifically for this study. This analysis was performed over the November1989 to
March 1990 time period.
The principal optioi s investigated were energy conservation, fuel substitution, reforestation,
methane control options, such as coal bed methane recovery and landfill gas recovery, and the phase-
Out of CFCs. These programs seemed to cover the lowest cost options available to reduce CO 2
emissions over the next twenty years.
The costs included in thi study cover equipment and installation costs, but they generally do
not include the costs of any government programs that would be required to achieve CO 2 reductions.
The achievement of any of the CO 2 reduction savings described in this study by definition would
require some kind of implementation program because all estimates are developed relative to a
projected market baseline In addition, the cost estimates do not include any second-order costs, such
as impacts on the coal industry due to reductions in demand for coal, or any feedback effects, such
as higher energy demand if efficiency standards reduced energy prices. This scoping analysis also
makes no attempt to quantify the benefits of greenhouse gas emission reductions.
Overall Results
Different methodologies for comparing the effects of CO 2 and other gases lead to different
estimates of the relative contribution of these gases to global warming. Figure 1 shows the relative
share of CO 2 and other greenhouse gas contributions to global warming in 1988 using the global
warming potential estimates developed by Working Group #1 of the Intergovernmental Panel on
Climate Change (IPCC, 1990).
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Page 1
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Figure 1
U.S. Contribution to Global Warming by Type of Gas in 1988
(Carbon-Equivalent Basis)
CFCs
21% (475)
The cumulative effect of implementing all of the low-cost options identified in the study up
to the limit of their potential is shown in Figures 2 and 3. The effects are measured in metric tons
of carbon, estimated on a C0 2 -e.quivalent basis for greenhouse gases other than CO 2 . Figure 2 shows
the effect on total carbon emissions when CFCs are included in the projections. Figure 3 shows the
effect when CFCs are excluded from the projections. The information is presented both ways
because some believe that CFC controls should be considered a fait accompli.
Methodology Used in the Study
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Page 2
The key elements of the study methodology were as follows:
• All CO 2 reductions were estimated relative to a market baseline
estimate of CO 2 or C0 2 -equivalent emissions.
• All global warming gases were converted to CO 2 equivalents. The
conversion rates used are the LPCC WG#1 estimates for a 100-year
time horizon shown in Table 1.
• The amount of CO 2 reduction was estimated in 2000 and 2010 based
on the savings from all incremental technologies in place in those
years due to programs that could be implemented as early as 1992.
• All projections were based on a common set of economic and energy
price assumptions. These assumptions are shown in Table 2.
1988 2240 lO 6 MetrIc Tone
N 2 0 7%(165)
5% (100)
-------
2
1.6
1
0.6
Figure 2
Effect of CO 2 Reductions on Total US. Fmicsions (Including CFCs)
0
use l isa
Y•er
Figure 3
Effect of CO 2 Reductions on Total U.S. Emissions (Excluding CFCs)
3.6
3
2.6
S
C
S
S
S
E
II
C
S
a
.3
C
S
a
S
U
S
C
S
0
S
0
S
C
0
S
C
0
0
0
0
S
C
0
=
=
S
1 i•2 11 i4 is iS isis 2000 2002 2004
2005 2005 2010
3.6
3
2.1
2
1.6
I
0.1
C
S
a
S
E
w
C
0
a
.3
a.
C
0
a
U
U
06W0658A
Page 3
a
liii isso i9i2 1 i14 i SiS 1968 2000 2002 2004 2006 2008 2010
V.ar
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TABLE 1..
Global Wárnnng Potentials Used to Convert Greenhouse Gases
to CO 2 Equivalence
(weight basis)
Gas
Global Warming
Co 2
1
CO
3
CH 4
21
N 2 0
290
CFC-11
3500
CFC-12
7300
HCFC-22
1500
CFC-113
4200
CFC414
6900
CFC-115
6900
a All values are on a C0 2 -equivalent basis for a 100-year time horizon.
Source: IPCC, 1990.
06W0658A
Page 4
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TABLE 2
Economic and Energy Price Assumptions Used in the Study
(1988 dollars)
1994) 1 1995
2O
Oil Prices
Crude Oil ($IBBL)
15.00
20.60
28.00
37.20
44.80
Jet Fuel (c/gaL)
0.52
0.66
0.89
1.15
131
Gasoline (i/gaL)
0.88
1.07
1.33
1.65
1.91
Diesel ( IgaL)
0.89
1.06
1.29
1.50
1.81
Residential: No. 2 ( IgaL)
0.82
1.00
1.23
1.51
1.75
Industrial: No. 2 (i/gaL)
0.60
0.77
1.01
1.27
1.48
Industrial: No. 6 ($/BBL)
14.00
19.40
26.50
35.40
42.55
Gas Prices ($/MMBtu)
Wellhead
1.70
2.65
3.70
4.65
5.80
Residential
5.40
630
7.25
8.10
9.15
Commercial
4.65
5.50
6.45
7.25
8.30
Industrial
2.80
3.65
4.65
5.45
6.50
Electric Utility
2.25
3.10
4.15
5.00
6.10
Electricity Prices (a/kwh)
Residential
7.7
7.2
7.2
7.1
7.6
Commercial
7.3
6.8
6.8
6.9
7.3
Industrial
4.9
4.5
4.6
4.7
5.0
Coal Price ($/MMBtu)
Industrial
1.55
1.60
1.70
1.85
2.20
Electric Utility
1.55
1.60
1.70
1.85
2.20
U.S. Population (millions)
250
260
268
282
295
Electricity Growth (annual)
2.3%
GNP Growth
2.5%
10 Growth
2.3%
Discount rate for cost curves
7%-real
06W0658A
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• The cost of all CO 2 reductions was estimated in constant 1988 dollars
on a levelized basis over the estimated useful life of the. investment
using a real discount rate of 7 percent.
• CO 2 reduction costs are presented as costs per ton of carbon removed
rather than CO 2 .
• Energy prices were used by different participants to estimate baseline
energy consumption in their CO 2 reduction categories. For sectors
not analyzed in this study, BA 1989 Annual Energy Outlook energy
consumption was used to create a national energy consumption
baseline.
• Avoided costs to the nation were used to estimate the savings from
CO 2 reduction options. A comparison of prices and avoided costs are
shown in Table 3. Avoided costs to the nation may be lower than
prices due to the exclusion of taxes or the fixed costs included in
regulated rates. For exarn le, a reduction in electricity consumption
at an individual house will reduce the costs to the consumer at the
average price, but since the fixed distribution costs to serve the house
(i.e., billing and house connection costs) do not change, the nation
saves only the generation and transmission fixed and variable costs.
TABLE 3
Comparison of Energy Prices and Avoided Costs Used in the Study
$/MMBTTJ
Electricity
2000 .
. . 2010 : :
Avoided Cost
$IMMBTU
Pace
$/MMBTU
Avoided Cost
$/MMBTU
Residential
21.10
16.99
20.81
18.16
Commercial
19.93
15.58
20.22
16.75
Industrial
. 13.48
14.28
13.77
15.46
Natural Gas
Residential
7.25
4.50
8.10
5.50
Electric Utility
4.00
4.00
5.00
5.00
Coal
Electric Utility 1.70 1.70 1.70 1.70
Gasoline
Gasoline I 10.63 8.24 f 13.19 10.79
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• The technologies used were to a very great extent “performance-
neutral,” in that savings were not obtained by reducing the nature or
the quality of the good or service provided.
• The estimated costs included only the direct costs of the investment
and did not include any macroeconomic or other indirect costs.
Neither was any effort made to analyze the feedback effects of
conservation on energy prices and energy consumption.
Although an attempt was made to have all study participants follow this same methodology,
not all of the inputs received from the different study participants were produced in the same
manner. Subsequently, ICF made an effort to adjust whatever was provided for consistency with this
methodology.
SUMMARY OF RESULTS
Tables 4 through 9 provide a summary overview of the results of the study for options in each
energy sector and for the non-energy options in the year 2000. Tables 10 through 15 provide similar
information for the year 2010. For each group of options data are shown on the total CO 2 emissions
reduced (in million metric tonnes of carbon), the total cost of the option, and the cost per metric
tonne of carbon emissions reduced; the energy options also include the total change in primary
energy. A listing of the CO 2 reduction costs for all the options in the study is included in Attachment
E
All of the sectors have significant opportunities for CO 2 emissions reduction. By the year
2000 the new and retrofit conservation options identified for the residential sector have the largest
potential for CO 2 reduction. By the year 2010 efficiency options in the transportation sector could
have a larger effeàt, as could substitution of renewable and other types of energy for coal in the
electricity generation sector.
A review of the tables reveals that the cost per tonne estimates shown are both positive and
negative. A negative cost means that the option would yield a net cost savings to the nation at a 7
percent discount rate.
The remainder of this report is devoted to documentation of the various greenhouse gas
emission reduction estimates. The first section discusses the energy-related emission reduction
strategies such as increased energy efficiency and alternative energy supply options; the second
section discusses the non-energy-related emission reduction strategies such as reforestation, methane
reduction options, and the phaseout of CECs.
06W0658A
Page 7
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TABLE 4
Summary of Energy Pmi sion Reduction Costs
Residential Sector
Year 2000
Prunaxy
Total Carbon
Tonne
Energy
Displaced
Total Costs
Carbon
Removed
(10 12 BTU) (10 ‘ 6 M l ’) (MM 88 $) (88 $IMT)
Shell Retrofit - Gas
1,402
20.259
$13,025
$642.91
Shell Retrofit - Electric
1,822
37.562
($7,281)
($193.83)
Electric Appliances
1,671
34.442
($6,092)
($176.87)
Gas Appliances -
Step 1
457
6.604
($178)
($26.99)
Gas Appliances -
Step 2
218
3.150
$4,077
$1,294.12
Fuel Substitution
- Step 1
0
2.784
($1,372)
($492.82)
Fuel Substitution
- Step 2
0
2.784
($252)
($90.52)
Sector Total
5,570
107.585
$1,927
$17.91
.
TABLE S
Summary of Energy Cost Estimates
Commercial Sector
Year 2000
Change in
Primary
Energy
Total Carbon
Displaced
Total Costs
Cost Per
Tonne
Carbon
Removed
(10 12 BTU)
(10 6 Ml ’)
(MM 88$)
(88 $IMT)
Conservation - St
ep 1
1,834
37.816
($4,329)
($114.48)
Conservation - St
ep 2
494
10.186
($342)
($33.61)
Conservation - St
ep 3
991
20.436
$1,054
$51.58
Fuel Substitution
- Step 1
0
0.905
($39)
($43.10)
Fuel Substitution
- Step 2
0
2.436
($805)
($330.46)
Sector Total
3,320
71.780
($4,461)
($62.15))
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TABLE 6
Suminaty of Energy Cost Estimates
Industrial Sector
Year 2000
Change in
Primaxy
Total Carbon
Cost Pe
Tonne
Energy
Displaced
Total Costs
Carbon
Removec
(10 12 BTU)
(10 6 MT)
(MM 88 $)
(88 $/MT)
Cogeneration - Step, 1
348
12 .999
($705)
($54.22)
Cogeneration - Step 2.
277
10.405
$1,709
$164.25
Cogeneration - Step 3
41
1.542
$1,150
$745.99
Cogeneration - Step 4
‘ 105
3.897
$7,734
$1,984.46
Industrial Heat Pumps
348
8.95
$1,470
‘ $164.23
Fuel Substitution - Step 1
0
4.439
$828
‘ $186.54
Fuel Substitution .- Step 2
0
1.740
$50
$28.74
Electric Motors
679
14.006
$7,858
$561.07
Sector TOtal ‘
1,798
57.977
$17,940
$309.43
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Page 9
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TABLE 7•’
Siimmaiy of Energy Cost Estimates
Transportation Sector
Year 2000
•
Primary
Total Carbon
Tonne
Energy
Displaced
Total Costs
Carbon
Removed
(1O 12 BTU)
(1O 6
MT)
(MM 88 $) (88
Light Duty Vehicles - Step 1A
151
3.233
($1,767).
($546.47)
Light Duty Vehicles - Step 2A
1,358
29.075
($7,659)
($263.43)
Light Duty Vehicles - Step 3A
302
6.466
($604)
($93.41)
Light Duty Vehicles - Step 4A
236
5.053
$526
$104.16
Light Duty Trucks - Step lB
173
3.704
($1,766)
($476.88)
Light Duty Trucks Step 2B
725
15.522
($4,756)
($306.40)
Light Duty Trucks - Step 3B
447
9.570
($1,489)
($155.53)
Light Duty Trucks - Step 4B
10
0.214
$21
$99.95
Air Transportation
39
0.835
($131)
($156.94)
Ethanol Substitution
0
0.000
$0
$0.00
Sector Total
3,441
73.672
($17,624)
($239.22)
06W0658A
Page 10
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TABLE 8
Summary of Energy Cost Estimates
Electric Utility Sector.
Year 2000
Chang ii
Primaiy
)La1 CarDon
tPer
Tonne
Energy
Displaced
Total Co
Carbon
emoved
(10 12 BTU)
(10 6 M’l’)
(MM 88 $) I (88 $IMT)
Hydro - Step
1
420
8.658
($522)
($60.29)
Hydro - Step
2
0
0.000
$0
$0.00
Wind - Step 1
276
5.690
($134)
($23.48)
Fuel Substitu
tion - Step 1
0
43.155
$8,050
$186.54
Fuel Substitu
tion - Step 2
0
._24.660
$5,200
$210.87
Sector Total
6%
82.163
$12594
$153.28
TABLE 9
Summary of Non-Energy
Emission Reduction Costs
Year 2000
Total Carbon Cost Per Tonne
DisplacedW Total Costs i Carbon
. . 1: d
(10 6 MT) (MM 88$) (88 $IMT)
Reforest Low
Cost Lands
9.26
$240.01
$25.92
Reforest Hig
h Cost Lands
9.02
$48331
$53.58
CFC Phaseou
t .
545.60
$1,312.00
$2.40
Landfill Gas
Recovery .
. 13.46
($305.00)
($22.66)
Coal Bed Me
thane Recovery
23.54
$0.00
$0.00
Methane from
Animal Wastes
1.09
$6.80
$2.97
All emiss
Values
ion expressed as carbon on a C0 2 -equivalent basis.
in parentheses are estimated cost savings.
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Page 11
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06W0658A
Page 12
TABLE 10
Summary of Energy Cost Estimates
Residential Sector
Year 2010
Change in
ost Per
Primary
Total Carbon
Tonne
Energy
Displaced
Total Costa
Carbon
Removed
(10 12 BTU)
(1O 6 MT)
(MM 88 $)
(88 $IMT)
Shell Retrofit - Gas
2,040
29.478
$19,013
$644.98
Shell Retrofit - Electric
1,634
33.678
($7,480)
($222.10)
Electric Appliances
2146
44.246
($8,020)
($181.26)
Gas Appliances -
Step 1
342
4.942
($342)
($69.20)
Gas Appliances -
Step 2
232
3.352
$3,176
$947.40
Fuel Substitution - Step 1
0
2.784
($1,736)
($623.56)
Fuel Substitution - Step 2
0
2.784
($616)
($221.26)
Sector Total
6,394
121.265
$3,995
$32.94
TABLE 11
Summary of Energy Cost Estimates
Commercial Sector
Yeat 2010
Change in
Primary
Energy
Total Carbon
Displaced
Total Costs
•;:: :.::. :
Cost Per
Tonne
Carbon
: R thoved .: :
(10 1.2 BTU)
(10 6 M l ’)
(MM 88 $)
(88 $/MT)
Conservation - Step
1
2,217
45.711
($6,081)
($133.04)
Conservation - Step
2
608
12.542
($657)
($52.37)
Conservation - Step
3
1,223
25.211
$837
$33.21
Fuel Substitution -
Step 1
0
0.696
($20)
($28.74)
Fuel Substitution -
Step 2
0
2.645
($1,231)
($465.44)
Sector Total
4,049
86.805
($7,152)
($86.42)
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TABLE 12
Summary, of Energy Cost Estimates
Industrial Sector
Year 2010
•
Primary Total Carbon
Energt Displaced Tote’ Co’s
Tonne
Carbon
Removec
(10 12 BTU)
(10 6 M l ’)
(MM 88 $)
(88 $IMT)
Cogeneration - Step 1
348
12.999
($338)
. ($26.01)
Co generation - Step 2
277
10.405
$2,012
$193.35
Cogeneration - Step 3
41
1_542
$1,195
$775.41
Cogeneration - Step 4
105
3.897
$7,842
$2,012.36
Industrial Heat Pumps
348
8.950
$1,334
$149.10
FuelSubstitution - Step 1
0
4.439
$1,188
$267.64
Fuel Substitution - Step 2
0
1.740
$75
$43.10
Electric Motors
926
19.099
$10,362
$542.54
Sector Total ‘
2,045
63.070
• $23,670
$375.30
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Page 13
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TABLE 13
Snmmary of Energy Cost Etimates
Transportation Sector
Year 2010
I
1
Prünaxy
Energy
Total Carbon
Displaced
Total Costa
Tonn
Carboi
Remav
(1O 12 BTU)
(1O 6 M’r)
(MM 88$)
(88 $IMT)
Light Duty Vehicles - Step IA
237
5.074
($3,157)
($622.14)
Light Duty Vehicles - Step 2A
2,664
57.036
($25,228)
($442.32)
Light Duty Vehicles -. Step 3A
616
13. 189
($4,257)
($322.75)
Light Duty Vehicles - Step 4A
387
8.286
($1,610)
($194.30)
Light Duty Trucks - Step lB
175
3.747
($2,669)
($712.28)
Light Duty Trucks - Step 2B
1,648
35.284
($16,348)
($463.33)
Light Duty Trucks - Step 3B
929
19.890
($7,144)
($359.18)
Light Duty Trucks - Step 4B
19
0.407
($115)
($283.51)
Air Transportation
95
2.034
($503)
($247.08)
Ethanol Substitution
893
19.119
($2,527)
($132.18)
Sector Total
7,663
164.065
($63,557)
($387.39)
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Page 14
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TABLE 14
Summary of Energy Cost Estimates
Electric Utility Sector
Year 2010
.....t..P.... ..
Priniaxy
Energy
Total Carbon
Displaced
Total Costs
Tonne
Carbon
Removed
(1O 6MT)
(MM 88 $)
(88$IMT)
Solar - Step 1
828
17.069
$2,319
$87.54
Solar - Step 2
276
5.690
$3,512
$48533
Geothermal
690
14.224
($799)
($56.14)
Hydro - Step 1
840
17317
($1,464)
($84.54)
Hydro - Step 2
420
8.658
$1,573
$181.68
Wind - Step 1
552
11379
($543)
($31.35)
Wind - Step 2
276
5.690
$4,341
$499.39
Biomass
690
14.224
$764
$53.68
IGCC
100
2.678
$4,716
$ 1,761.02
Nuclear
1,380
28.449
$2,247
$78.98
Fuel Substitution - Step 1
0
79.867
$9,900
$229.14
Fuel Substitution - Step 2
0
24.660
$17,040
$291.97
Sector Total
6,052
?T 9 04
: f43,607
$189.67
06W0658A
Page 15
(1O 12 BTU)
-------
TABLE. 15
Snmm ry of Non-Energy
Emission Reduction Costs
Year 2010
Displaced
:j:j
Total Costs ’
Carbon
Renioved
(10 6 MT)
(MM 88$)
Reforest Low Cost Lands
44.10
$412.33
$9.35
Reforest High Cost Lands
42.96
$802.14
$18.67
CFC Phaseout
90(193 $1,635.00
26.92 110.00)
30.70 $0.0
4.58 $13.6
$1.81
($22.66)
Landfill Gas Recovery
$0.0
Coal Bed Methane Recovery
$2.97
Methane from Animal Wastes
All emission expressed as carbon on a C0 2 -equivalent basis.
PJ Values in parentheses are estimated cost savings.
(88 $IMT)
06W0658A
Page 16
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I. DOCUMENTATION OF ENERGY MEASURES TO REDUCE CO 2
This section first presents the net effect on U.S. energy use of the energy conservation and
fuel switching options included in this report. Subsequently, the costs of the individual measures are
presented.
Energy Use Baseline and CO 2 Reduction Cases
The energy consumption baselines and CO 2 reduction measures prepared by each study
participant were assembled into a Year 2000 and Year 2010 set of scenarios. The Year 2000 results
are shown in Table 16. The Year 2010 results are shown in Table 17. The back-up material used
to prepare these scenarios is included in Attachment A.
A review of Table 16 reveals which sectors are most affected by the CO 2 reduction measures
in the year 2000. The conservation measures significantly reduce gas use in the residential sector,
electricity use in the residential and commercial sectors, gasoline use in the transportation sector, and
coal use in the electricity generation sector. In addition, gas use is increased overall due to the much
greater use of gas for electricity generation and cogeneration. The economic impacts of these
measures are very minor except in the coal sector. The coal industry would be severely impacted
because U.S. coal consumption is cut in haiL
A review of Table 17 reveals which sectors are most affected in the year 2010. The general
story is the same except for the greatly increased use of renewable energy in the transportation and
electricity generation sectors and the increased use of nuclear energy in the generation sector.
Vehicle Energy Conservation Measures
Numerous technologies are available that could be used to reduce energy use in vehicles.
These technologies have been evaluated within two vehicle categories; light duty vehicles and light
duty trucks (under 10,000 lbs.). Although each technology was evaluated separately, they were
grouped together into a few steps in the cost curves shown above for ease of presentation. Heavy
duty truck conservation and conversion from truck to rail were also investigated, but ultimately these
options were not included due to a lack of sufficient resources to complete the analysis.
The technologies used for light duty vehicles and light duty trucks are very similar. They are
listed in Table 18 along with the amount of energy saved in the fleet in 2000 and 2010 and the
estimated cost of energy saved in those years.
Source and Basis for the Estimates
The energy savings estimates represent the maximum feasible savings available over the period
from the identified technologies net of the amount of savings expected in the baseline. These net
estimates were developed based on work performed by Energy and Environmental Analysis (EEA),
the American Council for an Energy Efficient Economy (ACEEE), the Energy Information
Administration (EIA), and ICF Resources (ICP).
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TABLE 16
Year 2000 Energy Baseline and CO 2 Reduction Case
11-jul-90 ACTUAL BASE CASE CMANGES IN 2000 DUE TO LON C02
1988 2000 C02 REDUCTION PROGRANS CASE
ALL QUAJITITIES ARE IN
1O 15 OTU END-USE ELECTRICITY NATURAL GAS RENEWABLE
EPA CONSERVATION SUBSTITUTION SUBSTITUTION ENERGY
R.sid.ntIat
D Ist/LPG 1.61 135 -0.80 0.00 0.55
Gas 4.73 4.52 -2.08 0 ,80 3.24
Coal 0.07 0.05 0.05
Etec. 3.01 3.79 -1.13 2.66
9.42 9.71 -3.21 0.00 0.00 0.00 6.50
Co ric.t
Resid 0.25 0.13 -0.13 0.00
D$st/LPG 0.71 0.81 - -0.35 0.46
Gas 2.69 2.85 0 0.48 3.33
GasoLine 0.11 0.15 0.15
Coat 0.11 0.10 o. o
EL.c. 2.69 3.72 -1.08 2.65
6.56 7.76 -1.08 0.00 0.00 0.00 6.69
lró. trlat
Diet. L38 1.62 -0.24 1.38
LPG 1.6 2.06 . 2.06
GasoLine 0.22 0.26 . . 0.26
Resid 0.74 0.55 -0.39 -0.01 0.15
Fe.dstocks 0.81 1.12 1.12
Other Petr. 3.72. 3.58 .3.58
Gas 7.38 8.60 1.79 0.61 11.00
Coal 1.69 1.84 -0.55 -036 0.93
Nit. Cost 1.08 0.95 0.95
Etec. 3.03 3.90 -0.22 -0.66 3.04
Wood & Waste Fuels 0.17 0.23 0.23
a
21.82 24.71 -0.22 0.21 0.00 0.00 24.70
In-Plant Etec. Gin. 0.20 0.33
Trv portaticn
0 1st. 4.44 4.44 000 4.44
Jet 3.55 3.55 -0.04 3.51
GasolIne 14.4 14.40 -3.40 0.00 11.00
Resid 0.82 0.82 . 0.82
Nat. Gas 0.57 0.57 0.57
other P.tr. 0.29 0.52 0.52
ELec. 0.01 0.01 . 0.01
Ethanol 0.00 0.00 0.00 0.00
26.08 26.31 •3.44 0.00 0.00 0.00 20.87
Electricity
01st. 0.11 0.15 . 0.15
Resid 1.21 0.80 0.80
Gas 2.92 6.06 -3.75 -0.99 5.50 0.35 6.48
Coat 15.86 18.74 -375 099 -5.50 -0.35 8.16
NucLear 5.66 6.80 0.00 6.80
Hydro/Ren.w/Other \1 2.69 3.40 0.70 4.10
In orts 0.32 0.8 . 0.80
TotaL 28.73 36.75 749 1.97 0.00 0.00 26.49
Delivered Electricity 8.74 11.42 -2.43 -0.64 0.00 0.00 8.36
Total Prin ry Energy
011 35.97 36.31 ‘3.44 -0.39 -1.53 0.00 30.95
Gas 18.29 22.60 -5.82 0.80 7.39 -0.35 24.62
Coal 18.79 21.68 -3.75 -1.54 -5.86 ‘0.35 10.19
Nuclear 5.66 6.80 0.00 0.00 0.00 0.00 6.80
Nydro/Renew/Other 3.18 4.43 0.00 0.00 0.00 0.70 5.13
Total 81.87 91.82 13.01 -1.12 000 0.00 77.69
1. IncLudes utiLity hydro, wood generation. and non-irOjstrial OF generation.
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TABLE 17
Year 2010 Energy Baseline and CO 2 Reduction Case
11-Jul-90 BASE CASE CHANGES IN 2010 OUE TO L C02
2010 CC? REDUCTION PROGRAIIS CASE
ALL QUANTITIES ARE IN
10’15 8Th END-USE ELECTRICITY NATURAL GAS RENEWABLE
EPA CONSERVATION SU8STITUTIONSU8STITUTIO 1i ENERGY
Residential
•Dist/LPG 1.10 -0.80 0.00 0.30
Gas 4.70 -2.61 0.80 2.89
Coal 0.05 0.05
Else. 4.56 -1.22 3.34
10.41 -3.84 0.00 0.00 0.00 6.57
C eri cat
Res 0.10 -0.10 0.00
Dist/L.PG 0.85 -0.38 0.47
Gas 2.60 0 0.48 3.08
Gasoline 0.15 0.15
Coat 0.10 0.10
Et.c. 4.66 -1.31 3.35
8.46 - - -1.31 0.00 - 0.00 0.00 7.15
Ir mtrial
Gist. 1.90 -0.26 1.66
LPG 2.40 2.40
Gasoline 0.30 0.30
Resid 0.60 -0.39 -0.01 0.20
Feedstecks 1.40 1.60
Other Petr. 3.60 3.60
Gas 8.60 1.79 0.61 11.00
Coat 2.00 -0.55 -0.36 1.09
Met. Coat 0.60 0.60
ELse. 4.82 -0.30 -0.64 3.88
good & Waste Fuels 0.3 0.30
26.52 -0.30 0.21 0.00 0.00 26.43
In-Plant Etec. Gin. 0.69
Transportation
Gist. 5.15 0.00 5.15
Jet 4.05 -0.10 3.96
Gasoline 15.61. -6.68 -0.89 8.06
Resid 0.99 0.99
Nat. Gas 0.61 0.61
Other Petr. 0.50 0.50
Else. 0.01 0.01
Ethanol 0.00 0.89 0.89
26.92 -6.77 0.00 0.00 0.00 20.15
Electricity
Gist. .0.20 0.20
Resid 2.00 -1.20 080
Gas 5.78 -4.38 -0.99 9.00 -2.98 6.44
CaM 26.00 -6.48 -0.99 -7.80 -2.98 9.76
NucLear 6.30 1.38 7.68
Hydra/Renew/Other \1 4.30 4.57 8.87
Ie orts 0.8 0.80
Total 45.38 -8.86 -1.97 0.00 0.00 33.75
Delivered ELectricity 14.05 -2.86 -0.64 0.00 0.00 10.58
Total Pri ry Energy -
OIl. 40.90 -6.77 -0.39 -2.73 -0.89 30.12
Gas 22.29 -6.99 0.80 10.89 -2.98 24.02
Coal 28.73 -4.48 -1.56 -8.16 -2.98 11.60
Nuclear 6.30 0.00 0.00 0.00 1.38 7.68
Hydro/Renew.btea/other 5.40 0.00 0.00 0.00 5.47 10.87
Total 103.64 -1824 -1.12 0.00 0.00 84.2r
Includes utility hydrl. Includes utility hydro, wood generation, and non-in striat OF generation.
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• TABLE 18
PotentialEnergy Savings mLigbt Duty Véhicleand TruckFleets
VEHICLES TRUCKS
Cost Fuel Savings Cost Fuel Savings
$(MMBtn (Quad. Btu) $IMMBtu (Quad. Btu)
Technology 2000 2010 2000 2010 2000 2010 2000 2010
Aerodynamics 2.88 1.29 0.1391 0.2743 2.3 0.97 0.0766 0.1832
Additional Aero Improvements — — — — 6.12 2.42 0.0497 0.1120
Continuously Variable Trans. 6.94 3.02 0.0651 0.1173 3.56 1.54 0.0139 0.0305
Electronic Trans. Control — — — — 4.59 1.98 0.0253 0.0540
Engine Friction Reduction 6.28 2.71 0.0999 0.1835 4.55 1.96 0.0668 0.1464
5—Speed Auto Overdrive 11.35 7.08 0.0555 0.0901 6.03 3.67 0.0513 0.1018
4 Valve 3.39 0 0.2256 0.5307 2.03 0 0.1263 0.3304
Front Wheel Drive 4.71 4.76 0.0747 0.1199 —— -— — -—
Idle Off 2.95 1.77 0.1893 0.5320 2.39 1.44 0.1190 0.2608
Improved Accessories 5.07 2.29 0.0436 0.0808 0.79 0.38 0.0407 0.0932
Intake Valve Control 1.91 2.09 0.2714 0.4505 1.47 1.46 0.1752 0.3735
Lubricants — — — — 0.31 0.15 0.0253 0.0587
Lubricants/Tires 7.07 2.99 0.0311 0.0570 -—- —
Multi—point Fuel Injection 5.87 4.89 0.0621 0.1007 5.96 4.75 0.0448 0.0861
Overhead Cam Engine • 3.59 3.62 0.1354 0.2213 3.53 3.46 0.0953 0.1887
Roller Cam Followers 1.61 1.63 0.0214 0.0384 1.34 1.33. 0.0187 0.0399
Tires 13.91 8.46 0.0148 0.0239 10.38 4.72 0.0098 0.0188
Torque Converter Lockup 2.4 2.63 0.0178 0.0285 • 2.35 2.37 0.0204 0.0407
Transmission Management 1.32 0.86 0.2833 0.5452 1.04 0.67 0.1230 0.2780
Two—Stroke —3.46 -2.53 0.1506 0.2374 —1.97 -4.46 0.1728 0.1745
Weight Reduction 9.87 6.32 0.1657 0.2730 5.1 3.44 0.0994 0.1989
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The original maximum energy savings and cost estimates for light duty vehicles and trucks
were estimated by EEA. These estimates have been widely disseminated and discussed and formed
the starting point for all of the work performed. ACFFI- then took EEA’s savings estimates for each
technology, which EEA normally sums through a multiplicative approach (Le., two five percent
savings yield a 9.7 percent reduction), and added them linearly. Across all the EEA technologies this
approach increased the total savings above EEA’s estimates. ACi I-i- then added their own savings
estimates for aggressive transmission management and engine ..off options. Subsequently, ICF added
a savings and cost estimate developed by Dr. Marc Ross for two-stroke engines. The draft ACEEE
report is included as Attachment B.
The baseline for the vehicle fleets was taken from the EIA 1990 Annual Energy Outlook.
Since neither EEA nor ACEEE provided any estimates of the expected adoption of each individual
technology in the baseline (EEA provides a total estimate of savings from all technologies.), ICF
estimated the proportion of total savings available from all technologies required in the baseline to
yield the total assumed baseline efficiency improvement. ICF then assumed the rest would be
available at the cost cited by ACI- -h for the cost reduction step. ICF did not make any attempt to
estimate which of the identified technologies would be the ones more widely adopted in the baseline.
Problems with the Estimates
The U.S. automobile companies have argued that the EEA estimates of energy savings from
the identified technologies are too large and that the costs of the technologies are underestimated.
They claim that the technologies were more widely used in 1987 (the base year) than estimated by
EEA and that there remained less potential for further use. They further argue that the potential
savings from the individual technologies are double-counted, i.e., that the tests of individual
technology savings did not adequately separate Out the savings from other technologies also on the
test vehicles.
A further issue relates to the summation method used by ACEEE to calculate the total fuel
reduction achievable from the adoption of all the technologies. EEA has assumed that the effects
of the conservation technologies are overlapping to some degree and has reduced the total reduction
by taking only a multiplicative fraction of the saving obtained by each technology. ACEEE takes the
more aggressive posture that there is no overlapping. ICFs analysis of the aggregate difference
between these two approaches is included in Attachment C.
ICF’s estimates of the two-stroke technology’s savings may be overstated. ICF assumed that
the savings estimated by Dr. Ross were additive to the advanced four cycle engine savings estimated
by ACFFP This outcome is possible, but optimistic.
Another issue is the assumed change in vehicle performance over the period. ACEEE
assumes that the fleet’s characteristics do not change, i.e., that the average car does not get larger
or more powerfuL Further, ACEEE’s two technologies, aggressive transmission management and
engine-off at stops, may alter the performance characteristics of automobiles in a way that affects
acceleration. Any attempt to adjust the estimates to improve vehicle performance would reduce the
potential savings estimates shown.
Offsetting these assumptions that potentially exaggerate the potential savings at the estimated
cost is the likelihood that new technologies will be introduced that have not been included here.
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The two-stroke engine is an example of a technology not examined by EEA that will be entering
production within the next few years. Other technologies will undoubtedly come along.
Ethanol Use in Vehicles
Several alternative fuels could be used to replace petroleum in vehicles, including ethanol,
methanol, electricity, and hydrogen. Natural gas could also be used. In the time frame of this study,
the most promising fuel from a CO 2 perspective is ethanol produced from biomass. Currently,
ethanol is produced from agricultural crops, such as grain and sugar cane, at high cost, and most
experts agree that the opportunities to reduce costs require an alternative, lower value feedstock.
In this study the only alternative fuel program examined for vehicles was ethanol produced from
wood.
Three issues arise in ei mining the economics of using ethanol in vehicles: the cost of the
ethanol, the value of the ethanol as a substitute for a petroleum fuel, and the amount of petroleum
fuel replaced. In this study the cost of ethanol was assumed to be $0.85 per gallon at the plant gate,
$0.90 per gallon delivered to a refinery for gasoline blending, and $1.00 per gallon at a service station
(pretax) in 2010. Ethanol was assumed to be equal in value to gasoline as a blending component at
a 10 percent level of substitution.
Source and Basis for the Estimates
ICF was unable to find detailed documentation for the potential cost of producing ethanol
from wood in 2000 and 2010. This process is not commercial and has not been demonstrated, so
future costs are speculative.
As part of the development of the National Energy Strategy, SERI took the lead in an effort
to coordinate the development of estimates of future renewable energy costs by the DOE National
Laboratories. The latest results are published in The Potential of Renewable Energy: An
Interlaboratorv Analytic Paper , March 1990. This document estimates that currently the costs of
producing ethanol from corn is $1.28 per gallon and that the cost of producing ethanol from wood
at commercial scale would be $135 per gallon using existing technology. The document further states
that “Current research plans, based on the use of enzymatic hydrolysis technology, suggest that a goal
of $0.60 per gallon may be achievable as early as 1998 for ethanol from cellulosic and hemicellulosic
feedstocks.” (p. B-7)
Although the timing of improvements and the eventual production costs are speculative,
ethanol from wood does appear to be a potentially viable technology. ICF assumed no commercial
production by 2000 to provide sufficient time for demonstration and commercialization of the
technology. ICF further assumed that while good progress could be achieved in. bringing production
costs down to $0.85 per gallon by 2005, the $0.60 per gallon research goals set for 2000 were assumed
not to be met.
At the 10% level of substitution ethanol is a very valuable octane blending component in
gasoline. Even though ethanol has only 70% of the energy content of gasoline, its use as a high-
octane gasoline blending stock saves energy and costs roughly equivalent to the cost of a gallon of
gasoline on a volume basis because it reduces required crude oil processing and fuel use in the
refinery very significantly relative to the small amount of refinery output it replaces. High octane
gasoline blending components are among the most expensive and energy-intensive products produced
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in a refinery. Ten percent s a reasonable target percentage for gasoline substitution because at
higher blending levels ethancl’s marginal value falls as a component in today’s gasolines. Further
efficient use of ethanol would probably require engine and vapor recovery system redesign. Based
on work performed by ICF in the past and included in the DOE Report to Congress on the Alcohol
Fuel Reserve in 1983, ethanol was set equal to gasoline in value and energy on a volume basis as a
substitute at the ten percent leveL
Problems with the Estimates
The ethanol production cost estimates are speculative. Costs reductions like those assumed
require a wide array of technological and manufacturing improvements from a significant research
and development program.
With respect to the value of ethanol, the information in the 1983 Report to Congress should
be reevaluated. Since that time refiners have moved away from intensive reforming toward the use
of additives like MTBE or potentially ETBE to. raise gasoline octane. As a result, ethanol may now
be more or less valuable relative to gasoline than estimated in the 1983 report.
Aircraft Energy Conservation
Commercial aircraft engines continue to improve in efficiency, and forecasts of aircraft fuel
use take these improvements into account. Nevertheless, it seems that the ultrahigh bypass (UHB)
high-efficiency, unducted fan (UDF) engine, which was developed when oil prices were high, will not
enter commercial production before 2010. This engine has been demonstrated and licensed, so it
could be produced in large quantities very quickly, but at current and projected jet fuel prices its
economics are marginaL
This engine could be used for all new applicable commercial aircraft between 1992 and 2010
and to replace old engines on some aircraft at relatively low cost. The net savings would be 1.7
percent of projected jet fuel consumption in 2000 and 4.0 percent in 2010 at a cost (exclusive of fuel
cost savings) of $3.23 per million Bill saved.
Source and Basis for the Estimates
The source for these estimates is work performed by Michael Kavanaugh for this study, which
is documented in his memo of March 6, 1990. This memo is included as Attachment D to this report.
Mr. Kavanaugh estimates that the UDF engine could improve average fuel efficiency relative
to the average alternative engine by 16.8 percent over the 1992-2010 period. The UDF engine can
only be used on planes configured for rear engine mounting, which are used on short to medium haul
routes. Mr. Kavanaugh estimates that these planes will account for 43 percent of commercial jet fuel
consumption annually over the period. .
He reports that these engines cost $1 million or 25 percent more than conventional engines
and would lead to savings of 235,000 gallons of jet fuel per year for 15 years. He assumes no increase
in annual operating and maintenance costs.
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Problems with the Estimates
The approach used seems reasonable. A potential weakness is the $1 million estimate for the
incremental capital cost per engine. This apparently is the incremental price demanded by GE for
the engine in a failed attempt to line up a very large contract for it in 1989. It seems reasonable to
suppose that this price was closely related to the incremental production costs.
Residential/Commercial Energy Conservation
Electricity and natural gas are the principal energy types used in the residential and
commercial sectors. In this study the cost of reducing electricity and gas was estimated for the
residential sector and the cost of reducing electricity use was estimated for the commercial sector.
In both sectors appliance efficiency and building shell improvements were evaluated. Table 19 shows
the total savngs obtained for each fuel from each of these program categories. The detailed
information about all the programs in each category is included in Attachment E.
Source and Basis for the Estimates
These estimates were all created by the Lawrence Berkeley Laboratory (LBL). Their report
documenting these results is provided in Attachment E. ICF worked with LBL to adjust the costs,
calibrate the baseline, and reduce double-counting of the savings.
In the residential sector the estimates of potential incremental appliance energy savings were
developed using the LBL Residential Energy ModeL The available technologies and costs were given
to the Model along with baseline energy prices. The Model then created a baseline of technologies
used in the sector. Subsequently, the baseline estimates àf each technology’s use was subtracted from
an estimate of the maximum feasible use to create the potential incremental savings estimates for the
cost curves. The data on technologies came from the LBL data base that had been assembled to
support the DOE appliance efficiency standards.
The building shell improvement estimates were created separately in a more simplistic manner.
LBL projected the building shell condition of the typical existing electrically-heated and gas-heated
home in the years 2000 and 2010 and calculated the costs to retrofit these homes in each year.
Subsequently, these per house estimates were multiplied times the number of each kind of house in
the U.S. in the target years. Results provided do not distinguish between the costs of improving new
homes built during the period versus retrofitting existing homes. The savings estimates obtained were
then reduced to account for the effect of having first added higher efficiency appliances. The
estimates are based on the climate in Washington, D.C.
The methodology used for commercial buildings was similar, but it was based on non-LBL
data. The sources of the data are described in Attachment E No effort was made to eliminate any
minor double-counting between commercial appliance and building shell savings estimates.
LBL’s costs include three components: equipment costs, installation costs, and program costs.
Although implementation programs to obtain the estimated savings were not defined in this study,
LBL added 20 percent to all costs to cover possible implementation costs.
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TABLE 19
Savings for Residential/Commercial Electricity and Gas Conservation
(Trillion BTUs Measured at End Use)
Residential
Commercial
Electricity
Gas
Electric
2000 2010 2000 2010 2000 2010
Appliances
675
574
541
695
1063
1295
Building Shell
1402
2040
590
529
12
16
Problems with the Estimates
The allocation of building shell conservation costs to gas savings (for space heat) and
electricity savings (for space cooling) for homes using both energy types was not performed very
satisfactorily due to a lack of time. All of the costs were assigned to the gas savings and none were
assigned to the electricity savings. Consequently, the cost of gas reduction is overestimated and the
cost of electricity reduction is underestimated.
On average the other costs and the savings should be reasonable, but more work could be
done to improve the estimates for individual measures. If standards were used to implement the
appliance efficiency improvements, then the 20 percent implementation costs possibly could be
avoided. Building shell improvement cost estimates would be lower for new homes constructed over
the 1992-2010 period because the assumed retrofit for all homes is far more expensive. In contrast,
retrofit programs are very hard to implement. For the retrofit improvements for existing homes, the
costs might be higher and the savings might be lower or both.
A separate problem relates to the effect of aggregation. The estimates are all based on an
average U.S. house or building in an average U.S. climate. A more disaggregated regionaL /building
type analysis would undoubtedly lead to a greater range of costs to obtain the same savings.
Fuel Substitution
Natural gas may bà substituted for fuel oil or coal in various applications. This kind of
substitution has been taking place in recent years in the electric utility sector, where gas has replaced
residual fuel oil, and in the residential and commercial sectors. The costs of fuel substitution, aside
from any differences in the price of natural gas and the fuel being replaced, are the costs of
conversion or replacement of burners and the cost of building gas pipelines to consumers not now
served by gas. These costs vary by sector, and within each sector as discussed below.
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Electric Utility Sector
Many existing electric power plants have gas service. Based on ICF data on boiler fuel-
burning capabilities, we estimate that with no capital investment at least several Quads of gas could
be burned at existing plants now fueled with coal.
No substitution of gas for residual fuel beyond historic levels is assumed for electric utilities.
Due to seasonal limitations on gas transportation capacity, as discussed below, a cost of up to $1.00
per million Btu would be required to provide gas service to displace the remaining residual fuel.
Industrial Sector
Those industrial plants which are still burning residual fuel oil, even in markets in which gas
prices have been very competitive with oil, do so because there are limits on the existing interstate
gas pipeline (and storage) system. In almost all cases the oil-burning plants are connected to gas
lines, but cannot get gas during all or some o the winter season. In a few locations, such as paper
mills in rural areas, some plants do not, have ready access to the pipeline network. Based on the
estimated costs of proposed pipeline expansion projects for the northeastern U.S., we estimate that
capacity to supply additional gas in the winter would cost approximately $1.00 per million Btu. Some
projects in this cost range (for example the Iroquois Pipeline project) could begin construction soon.
Coal can be replaced with gas at many industrial facilities at zero ca ital cost. For this
analysis, which also includes industrial cogeneration and heat pumps, we have not included simple
substitution of gas for coal as an industrial CO 2 reduction program. Instead the substitution of gas
for coal as a boiler fuel has occurred as part of a cogeneration or heat pump substitution program.
These programs are documented below. Gas is assumed to be substituted for the coal used for
manufacture of cement, accounting for 20% of industrial coal use. No non-fuel costs were assumed
since many cement kilns have burned gas in the past; it is possible that minor retrofit costs would be’
incurred to switch back to gas from coaL
Commercial
A small quantity of residual fuel is still used in the commercial sector. We believe that this
is mainly the result of faulty marketing and pricing by gas distributors, who, partly due to regulation,
have set rates to these customers which are above oil costs, but also above the marginal cost of gas
service. We therefore project a zero cost to convert these customers to gas.
Distillate fuel oil and LPG used for heating (and other minor uses) in the commercial sector
could be replaced with gas. Part of this use occurs in areas with no gas service. We assumed .60
percent of the projected baseline oilILPG use could be converted to gas with the replacement of
existing burners, and in some cases with new hookups. A cost of $0.50 per million Btu is estimated
to be the average cost for these two situations. Burner replacement, at a cost of up to $1000 for
commercial furnaces, would cost about $0.25 per million Btu (assuming 600 MMBtulyear
consumption).
Residential Sector
Oil (and LPG) use in the residential sectors is for heating and hot water. The oil consumers
range from city home dwellers with oil furnaces and gas service for hot water and cooking to rural
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trailers heat 4 by 12G. To account for rural uses, 40 percent of the projected baseline oilfLPG use
was eliminated from consideration in 2000 and 30 percent in 2010. Of the remainder 1i2 is assumed
to be used in homes, primarily in the Northeast, where gas sexvice is available or can be provided at
very low cost. An average cost of $300 per household is estimated to cover a mix of burner
replacement and hook-up and replacement cases. One half of the potential market is assumed to. be
in existing suburban housing which does not have gas service. An average hook-up and conversion
cost of $2000 per household was assumed. Levelized costs are calculated based on assumed use of
60 MMBtu per year per house. The above estimates are based on ICFs experience, which includes
marginal distril,ution cost studies performed for gas utilities and studies of the New England and Mid-
Atlantic gas markets.
Source and Basis for the estimates
These savings and cost estimates are based primarily on undocumented ICF experience. Data
are available to confirm many of these estimates, such as oil and gas use in various categories of
housing, but no effort was made in this study to organize and review these estimates.
Problems with the Estimates
These estimates are reasonably accurate. The most significant problem is that the savings in
the residential and commercial sectors may well occur in the baseline. If so, no program would be
required for implementation.
There is a methodological issue associated with the cost of saving gas. In this study
conservation of gas in the energy consumption. baseline was assumed to save the marginal supply cost
of gas at the baseline gas supply leveL In fact, since the marginal cost would fall as conservation
increased, the gas cost savings would also decline. Ignoring this dynamic caused the conservation
program costs to be underestimated and the oil and coal to gas switching costs to be overestimated.
Incremental Gas Supply
The gas substitution programs shown above include gas made available through gas
conservation programs and gas obtained from incremental U.S. production. For the displaced gas the
cost is assumed to be the avoided cost from not using the gas. This is the same estimate used to
calculate the fuel savings value in the gas conservation options.
ICF Resources estimates that incremental gas above baseline levels could also be produced
in the U.S. over the 1992-2010 time period if sufficient financial incentives were provided the gas
industry. In this study two cxtra quads (i.e., quadrillion Btus) are assumed to be produced in 2000
and 2010 at a cost of $0.30 per million Btu above the wellhead price in the baseline.
Source and’Basis for the Estimates
ICF Resources est mated the quantity and cost estimates for the incremental U.S. production
by examining the results from previous runs of the ICF U.S. gas supply modeL
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Problems with the Estimates
This estimate is very approximate as it was made without ahy additional model runs. It should
be approximately correct
Renewable Electric Technologies
Renewable technologies could be extensively utilized to meet future U.S. electricity
requirements. The limits on the widespread use of renewable energy are more economic than
technical, so ICF’s analysis focused on the potential for low-cost renewable technologies in the
electricity sector.
Table 20 shows ICFs projected baseline use and the incremental contribution from renewable
electric, technologies that could be obtained in 2000 and 2010. These estimates rely heavily on
information provided by the Solar Energy Research Institute (SERI). The renewable technologies
considered include:
Hydro : Hydropower is an established technology that has been used
for decades forelectricity generation. Of the renewable technologies
included, hydro could make the largest near-term contribution to
incremental low cost generation (over and above the baseline).
Geothermal : Eectricity has been produced from the high quality
(vapor4omin ted) resource in the Geysers field in California for a
number of years. U.S. operating experience with the use of lower
grade (liquid-dominated) resources is limited to a few recently
completed plants that use either dual-flash systems or a binary cycle.
Advanced geothermal options such as hot dry rocks and geopressured
methane are not included in the attached projections.
TABLE 20
Potential for Low Cost U.S. Renewable Electric Generation
2000
2010
Baseline
Incremental
Baseline
Incremental
Mw bkwh Mw bkwh Mw bkwh Mw bkwh
Hydro
61,000
246
10,000
40
61,800
249
30,000
120
Geothermal
2,400
16
3,500
23
10,000
66
Wood
4,600
30
•
6,000
39
10,000
66
Solar
.
7,600
. 20
40,000
105
Wind
1,100
2.
15,000
26
11,400
20
45,000
79
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• Wood : Wood as a fuel for power generation is also a conventional
and proven technology. As with many conventional technologies there
is some, albeit limited scope, for making technological improvements
to lower costs and enhance efficiency. Advanced technologies, such
as combined biomass gasification/advanced turbine systems, were not
considered.
• Solar : The vezy limited operating experience worldwide indicates that
solar-electric technologies are technologically feasible, but their
lifetime economic and operating characteristics in the context of
overall power system operations remain an issue. The projections
presented here include two promising direct solar technologies —
solar-thermal and photovoltaics. Solar technologies are at a stage
• where the prospects for dramatic technological improvements are
likely to be greater than for established technologies such as hydro
and wood.
• Wind : Wind-powered generation’s technological feasibility has been
demonstrated, but there remain many issues about economics and
integration with the electric grid. As in the case of direct solar, the
underlying potential for future technological improvements is large.
Sources and Basis for the Estimates
The market baseline forecast was prepared by ICF (after an examination of SERI’s market
penetration for renewable energy estimated in their September 1989 interlaboratory paper) and
reflects a conservative view of (1) future technological improvements, (2) the willingness of project
developers and utilities to take major ris1 , and (3) current state and federal incentives for promoting
renewable technologies. The “incremental” penetration levels in this study are based upon SERI’s
“R&D Intensification Case”.
To estimate the cost per kWh of generating incremental electricity with renewable energy,’
ICF reviewed technology-specific cost and performance information from a number of sources
including SERI, Office of Technology Assessment, and EPRL The estimates of cost per kWh of
electric energy were then combined with various penetration levels to provide a limited number of
rough “steps” in a renewable energy supply curve.
Tables 21 and 22 present the assumptions used by ICF for renewable generation technology
costs and operating characteristics. Little renewable energy supply was assumed available by 2000,
but relatively low costs were assumed. For 2010 when the potential supply is much greater, ICF used
two cost steps for the hydroelectric, direct solar, and wind generating technologies. One step is
assumed to have relatively low costs while the second step is assumed to be at the upper end of the
range of costs estimated in the literature. The background information obtained from SERI is
included in Attachment L
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t ’: ’. ’.. ’-. ’ ::. :: :.. . : : : :: :.:. : : .:. :.. 1: ::: :::
TABLE 2F
Year 2000 Renewable Energy Cost Estimates
(1988 dollars)
Capacity Capital Alternate
Block. Coat Capacity 0&M Capac
(Mw) (5/kw) Factor (e/kwh) ( 51kw) -
: .H :
Step 1 10,000 1,375 46% 0.4 840
:: .nd.. : : :
Step 1 15,000 1,100 20% 1.0 840
TABLE 22
Year 2010 Renewable Energy Cost Estimates
(1988 dollars)
Sizeof Costof
Capacity : ‘ api }i . .: ‘. ... :. ‘.. Alternate:”.
BlOCk. ‘ ‘ . , C Z’. . Capacity’.: 0&M . .:. .:
(Mw): (5/kw) ‘. Factor ( /kwh). . (51kw)’
Hydro”’
Step 1
20,000
1,375
46%
0.4
840
Step 2 -
1O,000
3,500
46%
0.4
840
Geothermal
Step 1
10,000 I 1,367 I 75 3 .S ’ I 840
Wood ‘
‘
Step 1
10,000 I 3 433 I 75% I 3.6 ’ I 840
SoIar’
Step 1
30,000
2,000
30%
1.0
840
Step 2
10,000
4,000
30%
2.0
840
wind: :.:.
Step 1
30,000
1,400
20%
1.0
840
Step 2
15,000
3,000
20%
2.0
840
Represents a mix of conventional coal, combined cycle, and gas turbine capacity.
V Includes cost of fuel (e.g., geothermal brine, wood).
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Our assumptions on the capital costs, operating costs, and capacity factors for renewable
technologies in 2000 and 2010 are conservative. In part, our conservatism is based on the view that
the actual capital and other costs for renewable projects will be site-specific and will exhibit a wide
range of variation, while generic engineering estimates, particularly for 2000 and 2010, frequently
focus on “favorable” site-specific conditions. Thus, in providing a single average cost estimate for a
substantial supply block, we believe that a conservative estimate is more appropriate 1 ”.
In valuing capacity we provide a full capacity credit for both solar and technologies in spite
of their intermittent character. That is, we assume that based on their ability to provide capacity
when it is needed by typical utility systems, one MW of wind or solar capacity is equivalent to one
MW of , say, conventional coal capacity . Even with this assumption, the intermittent character of
solar and wind means that relative to conventional capacity they do not produce as much electric
energy per year for a given level of capacity, and this has a negative impact on their total cost of
production (in cents/kWh on an annual basis). Our assumpfion. assigning full capacity value to wind
technologies is overly optimistic, but it is offset by our relatively high capital cost estimates.
Problems with the Estimates
The estimates presented here can be used for preliminary “screening analyses”. Beyond this
the projections are of limited use. The specific problems with the projections are:
• Interpretation of SERI’s “R&D Intensification Case” : The total
penetration level under SERI’s “R&D Intensification Case” (which is
the basis for ICFs “low CO 2 case”) reflects potential penetration
under a combination of favorable circumstances such as rapid
technological improvements resulting in lower costs and improved
performance; reduction (and perhaps elimination) of certain
institutional barriers (e.g., environmental permitting for hydro); and an
assumption that the cost and performance of conventional
technologies will not improve. While determining the potential under
this combination of assumptions is useful, it is difficult to assign a
societal cost to some of the circumstances, such as, for example,
relaxing environmental permitting requirements for hydro sites.
• Resource Characterization : In the case of hydro and geothermal,
assumptions about the underlying resource base are critical. Even for
solar and wind, the prevailing energy intensity has to be developed on
11 Note, for example, that although there appears to be a widely-shared view that technological
developments will push down renewable capital costs over the long-term, ICFs year 2000,
step 1 supply block of 15,000 MW is lower cost than the year 2010, step 1 supply block of
30,000 MW (see total cost in cents/kWh in Tables 21 and 22). This is consistent with our
assumption that the larger 2010 supply block will likely include some marginal sites. This
impact is even more visible in step 2 of the 2010 supply block.
There is some evidence indicating a good correlation between the hours when utilities
requires capacity the most and the electric output of some selected, existing wind and solar
installations. (Research at PG&E offers at least preliminary support for this view.)
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a site- or region-specific basis. Even with considerable expenditure of
time, some questions related to resource uncertainty cannot be
completely settled. For a limited screening analysis, analysts are
forced to rely on gross characterizations. As a recent FERC report
on hydropower noted “. . .the estimates of conventional undeveloped
water power reflect the potential capacity of hundreds of individually
identified sites. The possibility of developing a particular site depends
on engineering, economic, environmental, and other considerations
which may change significantly over time...” While the current
estimates of market penetration for hydro in particular are consistent
with national studies of the “inventory” of undeveloped sites, the data
available did not allow us to categorize these sites even crudely into
“low cost” versus “high cost” sites. Similarly, we assumed that the
geothermal resource base is such that the future cost of geothermal
brine to the power producer (i.e., the fuel cost for this technology)
will not be substantially different from the current cost of brine. In
general, however, we would expect that as more resources are
explored and developed, the marginal cost of brine would rise. The
crudeness of this approximation is assumed to be accounted for by the
assumption that the higher end of the range of capital costs for
geothermal systems includes the larger exploration and devçlopment
costs of marginal resources. We do not, however, know that this
factor was explicitly accounted for in estimating geothermal capital
costs. Furthermore, the data available did not provide a sound basis
to estimate the proportion of the resource base for which the higher
capital cost would apply.
Inability to Distinguish Supply Imt,acts of Different Factors : It is
pàssible to construct a “supply curve” for each renewable technology
under alternative assumptions about the resource base, technology
costs and performance, and economic assumptions. Because adequate
information on the SERI forecasts relative to such factors as resource
base and causes for low or high technology costs was not available,
ICF was not able to develop a “ground-up” supply curve. For
example, a range of solar capital costs could reflect at least two
distinct factors: the technology itself; and the cost of construction and
installation at the site. To the extent this cannot be separated, it
complicates the task of e mining the economics at “good sites” versus
“poor sites”, assuming a given level of technology development.
Industrial Cogeneration
The use of cogeneration can lead to reductions in electricity purchases by industrial facilities.
Gas turbines are used to generate electricity, and the waste heat can be used to produce steam,
thereby displacing existing boilers. Generated electricity in excess of the facilities requirements can
be sold to third parties. ICF estimates of baseline fuel input for cogeneration and the boiler fuel in
the baseline available for additional cogeneration are shown in Table 23. Baseline cogeneration and
the potential for additional cogeneration were assumed to be the same in 2010 as estimated for the
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year 2000, reflecting the assumption that industrial demand for steam would not change during this
periocL
TABLE 23
Fuel Available For Cogeneration
(Trillions of Btu’s)
Year
Total Boiler
Fuel Use
Basehne Fuel
Input for
::: Cô ènà ion: .: .
Fuel Available
for Additional
Cogèné tibiiI
1985
6,770
768
2970
2000t2010
5,960
1,418
1,390
ICF estimates of the per unit costs for cogeneration of industrial boiler fuel are shown in
Table 24. Cost estimates were expressed in terms of dollars per unit of boiler fuel displaced by
cogeneration. Total costs of cogeneration were calculated by adding the estimated net fuel savings
associated with cogeneration to annualized capital cost estimates.
TABLE 24
Cost Estimates for Cogeneration
(1988 Dollars Per Muibtu)
Cost Ste
p
..
Quantity
(10 12Btu)
Capitai
Cost
Net Fuel
Savings
Total Cost
.
2000
2010
2000
2010
1
622
$2.42
$3.56
$2.97
-$1.13
-$0.54
2
506
$6.87
$3.49
$2.89
$3.38
$3.98
3
75
$18.81
$3.48
$2.87
$15.33
$15.94
4
186
$45.15
$3.57
$2.99
$41.58
$42.16
* All costs are expressed in 1988 dollars per million Btu of boiler fuel displaced by cogeneration.
Source and Basis for the Estimates
ICF Resources estimated the potential fuel available for cogeneration using the following
approach.
• 1. 1985 boiler fuel use per employee was calculated for each two digit SIC code industry
by multiplying reported energy use per employee estimates by assumed steam shares
• for each industry category. Energy use per employee estimates were taken from the
Department of Energy’s “Manufacturing Energy Consumption Survey” (MECS). The
MECS reports 1985 energy use for heat and power by manufacturing facilities by
industry category (SIC Code) and fuel type. The assumed steam shares used to
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calculated boiler fuel use are shown in Table 25. The steanr shares denote the
proportion of energy used for heat and power that was consumed in boil rs.
2. 1985 boiler fuel use per plant was estimated for four plant size categories by
multiplying the boiler fuel use per employee estimates calculated in (1) by the number
of employees per plant. The number of plants in each plant size category for each
SIC code category was taken from the 1982 Census of Manufacturers. These 1982
estimates of the number of plants were scaled so that total boiler fuel use matched
the total amount reported in the 1985 MECS. The plant size categories used were
as follows:
0- 99employees
100 - 499 employees
500 - 999 employees
> 1000 employees
3. Boiler fuel use by plant size category was projected for the year 2000 based on the
following assumptions: Coal use in boilers was assumed to increase by 25 percent
Gas use was assumed to decrease by a total of 40 percent below the 1985 level. Oil
use was assumed to remain constant at the 1985 leveL
4. Of the total oil and natural gas projected to be used in industrial boilers in the year
2000, one-third was assumed to be displaced through cogeneration in the baseline.
The remaining two-thirds of oil and natural gas use was assumed to remain available
for cogeneration.
5. Fuel available for cogeneration in 2010 was assumed to remain unchanged from the
year 2000 level, on the assumption that industrial steam demand would not change
during this period.
TABLE 25
Industrial Steam Shares and Capacity Factors
• •::.
SIC
:::: . . .
• •• . • .... .• . ..•
d
Ifl
.::,: :: ::...‘ .:: . c: . :: • ‘.
• ... Steam. Sha : . ..‘: .:. . •• .: •
to
Oil
. . : . .:
Gas
•:________
Coal
Major
By Ptod :
Other
:: :: c .:c
28&.30
Chemical, Rubber, Plastic
100.0%
80.0%
100.0%
0.0%
0.0%
88%
33
Prima y Metals
0.0%
15.0%
15.0%
0.0%
0.0%
70%
20
Food Processing
100.0%
67.0%
100.0%
0.0%
0.0%
40%
26
Paper
100.0%
100.0%
100.0%
100.0%
0.0%
85%
29
Refineries
50.0%
50.0%
50.0%
50.0%
0.0%
85%
32
Stone, Clay, & Glass
0.0%
0.0%
0.0%
0.0%
0.0%
—
34-38
Metal-Based Durables
100.0%
100.0%
100.0%
0.0%
0.0%
10%
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The net effect of cogeneration on fuel use was calculated based on energy balance analysis
for a representative cogeneration facility. The resulting net changes in fuel use per million Btu of
fuel displaced by cogeneration are reported in Table 26.
TABLE 26
Per Unit Change in Energy Use
Due to Cogeneration
(BTUs)
Boiler
Fuel
OIL
Gas
Electricity
Oil
(1.0)
1.90
(0.59)
Gas
0.0
137
(0.59)
In order to estimate the capital costs of cogeneration, boiler size estimates were first
calculated for each SIC industry category by dividing the estimated boiler energy use per plant by the
assumed number of hours the boiler operated during the year. Total hours of operation were
calculated by multiplying the assumed capacity factors shown in Table 25 by 8,760, the total hours in
a year. The capacity factors denote the proportion of time a boiler is in operation during the year.
ICF estimates of the annualized capital cost of cogeneration for each boiler size category are
shown in Table 27. These capital cost estimates were converted to a dollars per million Btu basis by
dividing the annualized cost estimates by the assumed total annual hours of operation for each boiler.
Total hours of operation were again calculated using the capacity factors in Table 25. For example,
the capital costs per MMbtu for a large boiler operating in the Paper & Allied Products industry (SIC
26) were calculated by dividing the annualized costs of $14,490 per MMBTU/hour by the total annual
hours of operation of 7,4.46. In this example, the total hours of operation were calculated by
multiplying the capacity factor of 0.85 shown in Table 25 for the Paper industry by 8,760, the number
of hours in a year.
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TABLE 27
Annuali±ed Capital Costs of Cogeneration
Energy Input Per
Hour
V
Annualized Cost
(Mmbtu/liour)
($/Mmbtu of Fuel
Displaced/Hour)
5
$49,150
10
$37,150
25
$26,030
63
$17,950
100
$14,990
As shown in Table 24 above, the total costs of cogeneration were calculated by adding the
net fuel savings to the annualized capital costs.
Problems with the Estimates
These estimates are only approximate because the base energy use data in boilers are old and
the assumed distribution of steam boilers by size is only approximate. Further, the future structure
and size of the U.S. manufacturing sector is uncertain. Nevertheless, it would be difficult to greatly
improve these estimates.
Industrial Heat Pumps
Industrial heat pumps are a commercially available energy conservation technology. Industrial
heat pumps re-cycle industrial process heat by using a compressor, usually powered by an electric
motor, to upgrade the heat from a source such as waste hot water or water vapor. Heat pumps may
be applied wherever steam is used and in applications, such as distillation of petroleum, where
another fluid is heated.
Most of the systems in place today are “open cycle” systems in which the vapor from a
distillation, drying, or concentration process is compressed directly and recycled. Open cycle heat
pumps often have very high efficiency, yielding ten or more units of energy output for each unit of
electricity used to operate the compressor. The most common application is in lumber drying.
Closed cycle systems, which operate analogously to an air conditioning compressor, are also in use,
but less widely. Open cycle systems are limited in their application to cases where the waste heat
resides ma vapor produced in the process, and where that vapor is free of contamination.
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ac,sed cycle heat pumps are often less efficient that open cycle types, but could be applied
very widely. There are no major technical problems to be solved in retrofitting indu trial heat pumps
in closed cycle applications, though it is a complex task to identify the optimal mix of energy
conservation measures for even simple industrial process plants. Industrial heat pumps do not have
a good reputation, due to early applications that were improperly designed.
The energy efficiency of a heat pump is measured by the coefficient of performance (COP),
the ratio of energy delivered by the heat pump to the energy required for compression. Often it is
possible to size the heat pump to meet a desired efficiency by determining how much of the waste
heat the heat pump will recover. The energy savings from heat pumps were calculated based on an
assumed design COP of 6. Each heat pump displaces 6 units of boiler fuel and consumes one unit
of electricity. According to information in the literature on heat pumps (see for example, EPRI EM
6057 Industrial Heat Pump Manual) , many applications can be identified which would permit systems
to be designed to achieve a COP of 6 or better.
The waste heat recovered by the heat pump displaces fuel which is used to generate steam
or to heat another fluid. For this study we have only included savings in boiler fuel. The boiler fuel
may be oil, coal or gas. The electricity might be produced using coal or gas as fueL If the electricity
is produced with coal, and the boiler fuel is gas, there is little or no CO 2 reduction from the heat
pump, at a COP-of 6. We therefore assumed that a heat pump program would be applied to plants
which use oil or coal as a boiler fuel (coal is the main target), except in the Gulf Coast region, where
gas is the marginal fuel for electric power generation.
The analysis also accounts for the implementation of a cogeneration program, which is
assumed to substitute for most of the steam now produced in boilers. The projected fuel used for
steam generation was therefore divided between industrial plants which will cogenerate, including
most of the gas-fueled plants, and plants which will install heat pumps.
Heat pumps are assumed to replaced 2 /3 of the coal and oil used for boiler fuel and 20% of
the gas. This adjustment is intended to eliminate applications where the application is too small, has
a poor capacity factor, or is otherwise unsuitable for economic installation of a heat pump. The
remaining boiler fuel is believed to be used primarily in plants with a high capacity factor.
The capital costs of heat pumps were estimated based on information in the EPRI Technical
Assessment Guide Volume 2: Electricity End Use (Part 3 Industrial Electricity Use), 1987. This
source indicates a cost of $2.1 million for a 40 MMBTU/hour system. The EPRI report also indicates
a constant cost per unit with increasing system size. Costs were annualized assuming a 14% capital
charge rate, based on a 15 year life and 7% real discount rate. An average capacity factor of 75%
is assumed, since the boiler fuel displaced is used in process plants which operate at high capacity
factors. The usual practice, where heat pumps are retrofitted to existing plants, is to retain the
boilers to meet peak steam requirements.
Problems with the Estimates
The estimates discussed above are based on a great simplification of the application of heat
pumps. In practice, every industrial plant would have a different optima! mix of cogeneration, heat
pumps, conventional heat exchange and other conservation measures. The COP, size, and capacity
factor of every system will differ. Costs depend on size and capacity factor. For this analysis a
constant cost per unit of installed capacity was used, while in practice there are likely to be some
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economies of scale. A single capacity factor was also assumed, while applications might vary from less
than 50% to a nearly 100% capacity factor.
Variable Speed Motor Drives
Variable speed motor drives (VSDs) can be used to improve the efficiency of motors that are
required to operate at varying loads. VSDs are now being used in industrial applications when motor
use is significant over the year, required speed varies, and the horsepower requirement is large.
There is considerable uncertainty about both the amount of motor replacement that will occur
in the baseline and the economies of any incremental use of VSDs. For this study a potential savings
of 220 trillion Btu’s in 2000 and 300 trillion Btu’s in 2010 was used at a levelized cost of $50.00 per
million Btu.
Source and Basis for the Estimate
For this study ICF reviewed previous work done by Argonne National Laboratory, Pacific
Northwest Laboratory, and Rocky Mountain Institute. Radian Corporation also analyzed the.
potential energy savings and related costs of VSDS for this analysis . Cost estimates for VSDs in the
literature vary over a very broad range. The Argonne study contains PNL cost estimates :for-VSDs
ranging from $92 to $450 per MMBTtJ of saved energy, with costs increasing sharply for small
motors. The Argonne report also contains cost curves used in the FOSSIL2 model that are of a
similar magnitude. However, Argonne’s own analysis documented in an appendix to their report
indicate VSDs could cost as little as $2.00 per M1’vfBtu. Rocky Mountain Institute also reports costs
for some VSDs as low as $2.75 per M?vIBTU. The wide range in cost estimates is apparently due to
different assumptions about the duty factor for different sized motors.
For this analysis, we have used the latest quantity and cost estimates developed by the Radian
Corporation for this study. Radian’s cost estimates are about $50.00 per MMBTU, roughly midway
between the costs reported in the literature.
Problems with the Estimates
The key problem with estimating the potential savings and costs of VSDs is that the data on
electricity use by motor size dates from the 1970’s. In addition, little data are available on the
distribution of the variation in motor load over time. Finally, the amount of VSD use in the baseline
is uncertain. Given all of these problems, improving these savings and cost estimates will be very
difficult..
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II. DOCUMENTATION OF NON-ENERGY GREENHOUSE GAS
EMISSION REDUCTION STRATEGIES
The following section discusses the non-energy greenhouse gas emission reduction strategies.
The discussion focuses only on five key options: reforestation, phaseout of CFC , landfill gas
recovery for methane reduction, coal bed methane recovery for methane reduction, and methane
recovery from animal wastes. Other options, such as N 2 0 reduction options and other methane
reduction options, offer very minimal reduction potential and/or are very costly.
Reforestation of Marginal Crop and Pasture Land and Unstocked Forests
Estimates of the cost of a tree planting program to sequester carbon have been calculated
based on a working paper currently under preparation for the EPA by Bob Moulton (U.S. Forest
Service) and Ken Richards (formerly Council of Economic Advisors) (Moulton and Richards, 1989).
These estimates take into account differences in land type, amount of available land, rental rates,
planting and treatment costs, and carbon sequestration rates for each region and land type.
The average unit cost of carbon sequestration under this program is about $14.15 per metric
ton carbon/yr in 2010. This cost estimate is based on reforestation of 59 million acres at carbon
sequestration rates of 1.81-126 metriC ton carbon/acre/yr. which is estimated to sequester 78-87
million metric ton carbon/yr in 2010 at a total annual cost of $1.2 billion. The weighted average land
rental cost is $23.48/acre/yr and treatment costs, annualized over 40 years at 7%, are $6.65/acre/yr.
For comparison, SERI has calculated that a national tree planting program on public and
private land could sequester 80-100 million tons carbon at a unit cost of $5-16/ton / year; however, the
inputs and calculations on which this analysis is based were not available at the time this report was
prepared (Tyson, 1989).
An overview of the key assumptions is provided below. Further discussion of this option can
be found in Attachment F.
Amount and Type of Land Enrolled
The amount of land potentially available for a tree planting program was calculated from U.S.
land surveys, which identified highly erodible, poor quality or wet crop and pasture land, and from
SCS/NRI reports of forest land being underutilized. 344 million acres fell into these categories and
were classified as land that could potentially be used in a national tree planting program. It .was
assumed in this strategy that up to 3.5 million acres could be reforested each year, with the program
beginning in 1992. Since it would take some time to get the program underway, it is assumed that
planting would start at 1 million (1M) acres in 1992, and increase to 1.SM in 1993, 2.OM in 1994,
2.5M in 1995, 3.OM in 1996, 3.5M in 1997 and thereafter until about 60 million acres have been
planted by the year 2010.
Carbon Sequestration
Incremental carbon capture (sequestration) per acre was calculated for each of the regions
and land types/qualities outlined above. The weighted average sequestration rate for all land enrolled
by 2000 is 1.81 metric tons of carbon per acre per year. Higher sequestration rates may be achievable
in the future with use of better genetically-engineered trees. However, achieving the adoption rate
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for these new strains may take decades since it takes time to determine the impact of any genetic
alterations. It was assumed that a 25% increase in existing sequestration rates may be achieved for
trees planted beginning in the year 2000. The weighted average sequestration rate for trees planted
after 1999 is assumed to be Z26 metric tons carbon/acre/yr. We have assumed that sequestration
rates increase linearly, from zero to the average rates presented above, during years 1-10 of the
stand’s lifetime. The stand is assumed to continue to sequester carbon at the average rate throughout
the rem Iining years of the analysis.
Costs and Revenues
Rental rates were based on rates paid out under the Conservation Reserve Program (CRP) 1 /
during past signups. Rental rates were adjusted upward to reflect the fact that the most eager renters
had already taken part in the program and were further adjusted for areas with high land values.
Rent is assumed to be paid on enrolled land for a total of 10 years from signup. Based on USDA
experience with similar programs, it is expected that very little land will be converted to other uses
once the 10-year period expires.
Treatment costs include the cost of preparing the land for planting, planting the trees
(including the cost of s edlings), and maintenance of the stand. Treatment costs were annualized
over 40 yrs at a discount rate of 7%.
No revenues from the sale of timber were assumed by either 2000 or 2010 due to the long
period of time it takes for a forest to reach a point at which it can be harvested.
Problems with the Estimates -
No large .scale reforestation program has ever been undertaken. Although the estimates
developed in this analysis are based on work currently ongoing at USFS and elsewhere, significant
questions remain to be resolved concerning: the amount of land that could be reforested and the
cost at which it could be made available; the rate at which carbon would be sequestered; and the cost
of planting and maintenance on these lands.
Costs of Phasing Out CFCs
The costs of phasing out CFCs were based on analyses conducted by the U.S. EPA/Office of
Air and Radiation; a summary of this work can be found in “Costs and Benefits of Phasing Out
Production of CFCs and Halons in the United States,” OAR/EPA, November 3, 1989 (hereafter
referred to as the ‘Thaseout Report”).
Table 28 summarizes the amount and cost of emission reductions resulting from a CPC
phaseout. A CFC/Halon phaseout is estimated to reduce emissions by 546 million metric tons in 2000
.1/ The CRP program is administered by the USDA to take annually tilled marginal crop land
out of production for periods often years. Rent is paid to the landowners to offset the costs
of other opportunities foregone. Land which qualifies for this program is generally highly
erodible and one of the requirements of the CRP program is that soil management practices
must be implemented. Planting trees is one way to satisfy the requirement that a permanent
cover crop be planted to prevent soil erosion.
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TABLE 28
Quantity and Cost of Emission Reductions Resulting from a CFC Phaseout
Actual nu sion Reductions
(Millions of K& C0 2 .Equ ivalent Carbon Emissions)
Year 2000
Year 2010
CFC and Halon Reductions
588,935
957,676
Substitute Pmi sjons
(43,967)
(57,419)
Trace Gas Pmissions
631
676
Total Reduction
545,599
900,933
Cost of Reductions
( Mffli sof1988DoIlara) . .
Year 2000
Year 2010
Cost Without Energy Impact
$1,456
$1,668
Energy Savings
($144)
($33)
Net Cost including Energy Impact
$1,312
$1,635
and 901 million metric tons in 2010. These reductions have been adjusted by the global warming
potential factors for each compound and are expressed on a carbon-equivalent basis. The cost of a
CFC phaseout in 2000 is about $1.3 billion, or about $2.44) per metric ton of carbon. In 2010 the cost
of a phaseout is $1.6 billion, or about $1.81 per metric ton of carbon.
An overview of the methodology used to determine these costs is presented below. For a
more complete disc ssion, see Attachment G.
-
Methodological Approach
The general framework used to develop the CFC phaseout costs is to calculate the costs of
introducing controls and then estimate the emission reductions resulting from their implementation
for a given year (e.g., 2000 or 2010). However, the proposed rule for a CFC and halon phaseout
mandates that the production , not emissions , of CFCs and halons be phased out by the year 2000.
As a result, the modelling framework used by OAR calculates the cost to industzy of reducing CFC
and halon use to levels that comply with the production phaseout. Because of the nature of CFC
equipment, reductions in the use of CFCs in a given year do not necessarily translate into reductions
in CFC emissions in that same year. This is because many of the types of equipment contain a CFC
or halon charge that can remain in the equipment for decades. Indeed, this charge may leak slowly
over time, may be vented at servicing or disposal, or may be collected for recycling purposes. This
“banking” of CFCs and halons in equipment complicates the calculation of costs and actual emissions
for a given year because the emission reductions for that year result at least partially from controls
implemented (and costs incurred) in previous years.
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Given thesecomplications; we calculated the total cost of the phaseout and the total actual
reductions in CFC and. halon emissions in the years 2000 and 2010. This approach will tend to
overestimate the cost per unit of emission reduction because (1) controls in 2000 and 2010 affect
emissions in many subsequent years; and (2) a portion of the actual emission reductions in 2000 are
due to control actions undertaken in prior years in which a phaseout was not required. This
approach seems most appropriate for this study since we are interested in emission reductions that
can be achieved by a certain date.
The Phaseout Report estimated the costs, CFC and halon emission reductions, increases in
chemical substitute use, and changes in energy use resulting from a phaseout of CFCs and halons in
the United States by 2000. These were estimated by simulating the introduction of controls in the
current and expected future stock of CFC and halon equipment. These controls may include
chemical substitutes, product substitutes, and process changes (e.g., recycling).
The Phaseout Report identified these cost and energy impacts by undertaking the following
steps for each CFC and halon consuming end use:
• estimating CFC/halon use, energy use, and life-cycle costs in baseline (i.e.,
uncontrolled) equipment;
• specifying the impact that individual controls, such as a chemical substitute, may have
on CFCIhalon use, energy use, and costs in the eqUipment;
• defining alternative groups of controls, referred to as “control plans,” for each
equipment type that may be implemented over time to meet regulatory restrictions
on CFCs and halons;
• selecting a least cost control plan for each equipment type that may be adopted in
response to a phaseout;
• summarizing total costs and reductions for the U.S. associated with the
implementation of these control plans; and
• estimating emissions of chemical substitutes and changes in energy use for the
selected control plans.
Prior to the year 2000, CFC and halon use is restricted to use levels required under the
Montreal ProtocoL As a result, a portion of emission reductions in 2000 and 2010 will be due
to control actions that were implemented to achieve less than a complete phaseout.
It is also assumed that industry complies with the Montreal Protocol prior to the year 2000.
This Protocol mandates a production freeze of CFCs at 1986 levels in 1989; a 20 percent
reduction of CFCs from 1986 levels in 1993, and a 50 percent reduction of CFCs from 1986
levels in 1998. Halon production must be frozen at 1986 levels beginning in 1992.
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End uses included in the analysis were:
• aerosols;
• foam insulation;
• commercial refrigeration;
• residential refrigeration;
• mobile air conditioners;
• solvent cleaning;
• sterilization; and
halon fire extinguishers.
Total costs, emission reductions, substitute use, and changes in energy use were calculated by
summing across all end uses for each year. This data was then translated into estimates of the cost
of a CFC phaseout per unit of equivalent carbon dioxide reduction.
Problems with the Estimates
The costs of a phaseout have been extensively analyzed by EPA’s Office of Air and Radiation.
Since the cost analysis presented here was based on the results of all of this work, we have a fairly
high level of confidence in the cost estimates. There are two possible problem areas. First, as noted
above the reductions were based on estimated emission profiles that depend on end use, equipment
maintenance schedules, extent of recycling, etc. The information on estimated releases reflects the
best available; nevertheless, actual release schedules may vary somewhat. Second, the Phaseout
Report used a 6% discount rate, not the 7% rate used for the other cost estimates in this study. Due
to budget and time constraints, the analysis was not redone using the 7% rate. Our use of the 6%
rate increases the cost estimates to some extent, but this does not significantly affect the cost
estimates.
Methane Recovery from Municipal Landfills
The anaerobic decomposition of deposited waste by microbes produces landfill gas, which is
approximately 50% methane gas and 50% carbon dioxide. The rate of landfill gas productioti
depends on many factors, including temperature, moisture, size, contents, and age of the landfill.
Rather than letting methane escape into the atmosphere, it can be flared or captured via a landfill
gas recovery system and either used as fuel to generate electricity, or sold as medium or high Btu gas.
Based on the analysis presented below, if methane recovery systems were installed on those landfills
holding over one million tons of waste, we have assumed that approximately 55% of methane
emissions could be recovered and used as energy.
In the U.S. there are 6,034 active landfill sites at which about 190 million metric tons of waste
were disposed in 1986, according to data from EPA’s 1986 Solid Waste Survey (U.S. EPA, 1988)..
In this study specific waste disposal information was provided for 265 landfills with overall disposal
capacities larger than one million metric tons. Landfills at least this size are important because, as
a general rule, they comprise the sites at which it is considered economic to install a methane
recovery system (based on data from the Michigan Electricity Options Study as reported in ICP,
1987). For purposes of this analysis, we assumed that all landfills in this category would install a
landfill gas recovery system and use the gas to generate electricity sold at $0.05/kwh (we did not
assume landfill gas recovery as part of any regulations requiring recovery to minimize fugitive
emissions for safety or aesthetic reasons; such regulations have been proposed, but we have focused
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on those sites that appeared the most economic regardless of other regulations). In the absence of
any program, we assumed that no landfills would recover landfill gas and generate electricity (Some
facilities are currently operating, but we had no data on their recovery or disposition of gas).
We did not know exactly how much waste was handled at each site. Of the 265 sites for
which there were data, 133 were classified as “large” (receiving greater than 500 tons of refuse per
day), while 132 were classified as “small ”(receiving less than 500 tons of refuse per day). Although
data were available only for 133 “large” sites, the 1986 Solid Waste Survey identified 362 large”
• landfills. For the 229 sites for which no data were available, we assumed that they had disposal rates
equal to the average of all sites for which data were available, i.e., about 285,000 metric tons per year.
This approach allowed us to estimate total waste disposal at 494 landfills — the 265 landfills for which
we had data plus the 229 landfIlls for which we estimated the amount of waste disposed. As a result,
the total yearly amount of refuse deposited in these landfills is about 144) million metric tons. That
is, these 494 landfills (the largest 8.1% of all landfills) contain about 74% of all waste landfilled
annually.
Assuming that yearly waste disposal rates are indicative of total waste disposed at landfills as
well as the amount of methane production, we assumed that the 494 landfills would emit 74% of all
methane from landfills. In the U.S. approximately 8.3-11.0 Tg of methane are emitted yearly from
landfills (Cicerone and Oremland, 1988). This estimate takes into consideration waste that has been
in place for several years as well as that which has recently been deposited, since waste may continue
to generate methane for 5-20 years. The 494 landfills we have targeted would then be responsible
for 6.2-8.2 Tg since they receive approximately 74% of total U.S. waste. Methane recovery was
determined assuming 75% of the methane generated was captured. Therefore, between 4.7-6.1 Tg
of methane would be recovered annually.
The amount of electricity produced from this amount of methane was estimated by assuming
680 grams/rn 3 and 3.53 kwhlm 3 . Capital costs were assumed to be $1000/kW and operation and
maintenance costs were assumed to be 5% of capital costs (based on Michigan Electricity Options
Study, ICF, 1987). At a 70% capacity factor for a gas turbine installed with the gas recovery system,
annualized costs to produce electricity would be about S0.025/kwh. With an average price for
electricity of $0.05/kwh, landfill gas recovery systems would generate about $0.025/kwh in savings, or
a savings of about $130 per metric ton of methane recovered. Moreover, landfill gas recovery would
not only avoid the emissions of methane to the atmosphere, generation of electricity from the
methane would also reduce the need for generation by electric utilities, much of which is fossil-fuel
based generation.
Problems with the Estimates
The quantity and quality of waste may be affected by a number of factors, including more
aerobic landfill conditions via aeration, increased incineration, recycling, and composting. This would
rid landfills of significant amounts of organic matter, thus reducing methane gas generation.
Several other factors also affect recovery from landfills. For example, projects may not prove
economically viable if sufficient gas users are not within 2-3 miles of the site, or if the utility buyback
price for electricity is unfavorably low. Additionally, resource recovery projects in some states may
be subjected to unlimited liability for any potential area contamination in the landfill, regardless of
its association with the recovery equipment.
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87 recovery systems currently operate on U.S. landfihl (30% of the Iandfihl are closed), while
68 are in the planning and construction stages. Our estimates did not adjust for these facilities
because we had no data on amounts of gas recovered and the method used to dispose of the
recovered gas.
Coal Bed Mefhflne Recovery
Methane trapped in coal seams is emitted to the atmosphere as a result of coal mining
activities. We have estimated the potential to reduce these emissions based on a draft report
produced by U.S. EPA/OAR entitled “Methane Fmi sions to the Atmosphere from Coal Mining,”
January 5, 1990.
Globally, about 47 Tg methane were released during coal mining operations in 1987, of which
the U.S. emitted about 7 Tg, or 15% of the world’s total. Using the baseline energy forecasts
assumed throughout this study, demand for coal in the U.S. is expected to increase from 19 quads in
1987 to 22 quads in 2000 and to 29 quads in 2010. As an approximation of future emissions from
coal beds, emissions were assumed to be linearly related to total coal production. This approach
yields an increase in baseline methane emissions from 7 Tg, rr in 1987 tO 8.21 Tg/yr in 2000 and 10.71
Tg, rr in 2010. This is probably an underestimate since more coal is being deep mined than stripe
mined and coal mining is increasingly occurring at greater and greater depths; both of these trends
would tend to increase the amount of methane from coal mining .
The draft OAR study indicates that significant quantities of methane can be captured and
often sold at a profit, either directly as gas or for on-site electricity production and subsequent sale
to utilities. We assumed that a 50% reduction in methane emissions could be achieved each year by
capturing methane both prior to coal mining and after mining as a result of additional methane
releases from the coal mining operations. This is a simplifying assumption; actual recovery varies
depending on many factors, including type of mining method, depth of coal seam, geological
characteristics of the seam and surrounding strata, and degasification method. Based on a 50%
methane recovery rate, emissions in 2000 and 2010 would be reduced 4.11 and 5.36 Tg/yr,
respectively.
As indicated above, there are two options-for the-use-of coal bed methane: (1) direct sale of
the gas, and (2) the use of the gas for electric power generation with subsequent sale of electricity.
For purposes of this analysis, we assumed that, given the remote location of most coal fields, gas
transmission lines would not be readily available and would be too costly to install. Therefore, we
assumed that all coal bed methane recovered would be used to generate power. Such power
generation would also have the added benefit of backing out electrical generation from utilities, much
of which is fossil-fired power generation. We assumçd that the net cost of methane recovery from
coal seams would be zero, i.e., that the cost of the recovery option would be offset by the benefits
of power sale and possible improvements in mining conditions. This assumption could underestimate
or overestimate the costs of coal bed methane recovery depending on many factors, including the
methane recovery rates, overall quantity recovered, value of the electricity (or natural gas) produced,
etc. These factors could be evaluated with further analysis.
Problems with the Estimates
Our zero cost assumption may be conservative. Preliminary analysis on coal bed methane
recovery indicates that it generally is profitable given the current advances in gas recovery technology.
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There remain barriers to recovery of this gas, however. In addition to the factors noted above that
affect the quantity of gas recovered, in many states there are many legal issues surrounding ownership
of the coal bed methane, e.g., does the methane belong to the coal company or to the natural gas
company with drilling rights on the property? These issues would need to be resolved before coal
bed methane recovery becomes a reality in some areas. Also, although electricity production from
coal bed methane could back out other forms of electricity from the utility grid, the emission credits
due to this benefit were not incorporated here.
Mefhnne Recovery from Animal Manure
Decomposition of manure under anaerobic conditions can result in the production of
methane. These conditions often occur when large numbers of animals are managed in a confined
area (such as in dairies, beef feedlots, and swine and poultry farms) where manure is usually stored
in large piles or disposed of in lagoons. Since these types of animal management operations are
usually energy intensive, they could potentially save a large portion of their energy bills by capturing
this methane to replace energy currently purchased from utilities. Additionally, by capturing methane
from decomposing animal wastes to replace current energy use, greenhouse gas emissions could be
reduced by the amount of carbon that would have been released by the utilities plus the amount of
methane emissions reduced. Only the methane emission reductions are quantified here.
Based on USDA data and ASAE (American Society of Agricultural Engineers) manure
production statistics, we estimate that roughly 400 million tons of manure (wet weight) are produced
each year by the managed animals mentioned above. It is not known how much of this manure
decomposes under anaerobic conditions: we have assumed 25%. We have assumed conservatively
that about 8 kg CH 4 is produced per ton of manure in an anaerobic environment (U.S. EPA, 1989),
resulting in about 0.8 Tg of CH 4 released annually from this source.
Cost of Reducing Emissions
There are two systems currently being developed and implemented which derive useful energy
from manure: (1) One system involves trapping gases emitted from manure lagoons; the trapped
methane can then be burned for the production of electricity or used to replace natural gas on site;•
(2) For manure which is not disposed of in lagoons, an anaerobic digester can be used to extract
methane. We have developed cost estimates based only on very limited data for anaerobic digesters.
Moveover, these cost estimates may not adequately represent future costs since they are
approximations of current costs and do not account for some factors such as new technologies and
potential economies of scale. Additionally, costs of constructing biogas combustion facilities vary
depending on the size of the facility, proximity of the combustion facility to the gas production
facility, materials used, etc. Revenues also vary depending on CH 4 production rates (which increase
with temperature) and electricity and gas prices.
There is little data on the cost of methane recovery from these operations; we have used
information for anaerobic digesters based on a 200 cow facility in Maine (Criner, 1987). Capital costs
for this facility were $105,000 with annual operating costs of $5,100, resulting in total annualized costs
of about $15,000. We assumed electricity production from anaerobic digesters is 2 kwh per head per
day (Parsons, 1984), resulting in energy savings of about $6,860 for a net cost for the operation of
about $8,100. Thus, the unit cost of reduction is about $17/ton CH 4 .
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Problems with the Estimates
Based on the analysis presented here, we estimate that about 0.8 Tg of CH 4 emissions can
be reduced at a cost of about $17/ton with the following caveats: (1) emissions estimates are highly
variable, depending on estimates of animal populations and manure production and assumptions of
storage practices and amounts of gas captured and (2) cost estimates are very approximate since they
are based on limited data that may vary widely depending on site characteristics, technology selected,
etc.
Biogas combustion facilities have been operating and are currently being installed in the U.S.
(it is estimated that about 100 facilities are currently being operated in the U.S. [ Safley, 19891)
suggesting that these facilities can be operated at a profit. However, incentives will have to be
provided in order for this technology to become widespread. Because of the high capital costs, risk
associated with a new technology, uncertainty surrounding future energy prices, and perceived barriers
to the sale of excess electricity, most farms are not considering this technology at this time.
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SFLPcii J) REFERENCES
Argonne National Laboratoty, 1989. Technology Characterizations and Policy Options to Reduce GHG
Emissions: Industrial Sector, June.
Cicerone, RI. and R.S. Oremland, 1988. Bibgeoc .hemical 4spects of Atmospheric Methane. Global
Biogeochemical Cycles . 2(4).299-327.
Criner, G.K., 1987. Economic Feasibility of Anaeombic Digesters, Biocvcl 28(2)51-53.
EPRI, 1987. Technical Assessment Guide, Volume 2. Electricity End Use. Part 3: Industrial
Electricity Use. Electric Power Research Institute 1987.
ICF, 1982. dnalysis of a StrategicAlcohol Fuel Reserve,” prepared for the U.S. Department of Energy,
December 1982.
ICF, 1987. The Potential for’ Biomass, Waste to Energy, and Hydroelectric Power in Michigan,
Presented to Michigan Electricity Options Study, January 1987.
ICF, 1990. Methane Emissions to the Atmosphere from Coal Mining, draft report prepared by ICF
Resources to U.S. Environmental Protection Agency/Office of Air and Radiation, January 5, 1990.
IPCC, 1990. Scientific Assessments of Climate Change, Draft Report of Working Group #1,
Intergovernmental Panel on Climate Change, April 30, 1990.
Kavanaugh, 1990. Fuel EconomiesAvaikble from Ultrahigh Bypass (UHB) Jet Engines, Memorandum
from Michael Kavanaugh to P. Schwengels and B. Solomon, U.S. EPA, and T. Breton and J. .Blaney,
ICF, March 6, 1990.
Ledbetter, M. and M. Ross, 1989. Supply Cw-,es of Conse,ved Energy for Automobiles, American
Council for an Energy-Efficient Economy, Draft Report for Lawrence Berkeley Laboratory,
December 1989.
Lovins, A.B., 1989. The State of the Art: Drivepower, Rocky Mountain Institute, Snowmass,
Colorado, April
McMahon, J.E., 1990. Supply Curves of Conserved Energy: Residential and Commercial Sectors,
Lawrence Berkeley Laboratory, March 2, 1990.
Moulton, R. and K. Richards, 1989. Costs, of Sequestering Carbon Through Tree Planting and Forest
Management in the U.S. U.S. Forest Service technical paper, draft (in revision), fall 1989.
Parsons, R., 1984. On-Farm Biogas Production. Northeast Regional Agricultural Engineering Service
Cooperative Extension, NRAES-20, Cornell University, Ithaca, N.Y.
Safley, LM., 1989. Methane Production fromAnimal Waste Management Systems. Prepared for U.S.
EPA workshop Methane Emissions from Ruminants. February 27 28, 1989.
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‘SERI, 1990. The Potential of Renewable Energy: An Interlaboratorj Analytic Paper, draft report
prepared for U.S. Department of Energy by Solar Energy Research Institute, March 1990.
Tyson, K.S., 1989. Agriculture and Land Use. Prepared for inclusion in Ca bon Dioxide Inventory
and Policy Study . U.S. Department of Energy.
U.S. DOE, 1983. 1982 Census of Manufactures: Fuels and Electric Eneigy Conswned. U.S.
Department of Commerce, June 1983.
U.S. DOE, 1988. Manufacturing Energy Consumption Survey: Consumption of Energy, 1985. Energy
Information Administration, U.S. Department of Energy, November 18, 1988.
U.S. DOE, 1989. Annual Energy Outlook 1989. Energy Information Administration, U.S.
Department of Energy, January 10, 1989.
U.S. DOE, 1990. Annual Energy Outlook 1990. Energy Information Administration, U.S.
Department of Energy, 1990.
U.S. EPA, 1988. National Survey of Solid Waste (Municipal) Landfill Facilities, Draft Report, Office
of Solid Waste and Emergency Response, Washington, D.C., EPAJS3O-SW88-034, September 1988.
U.S. EPA, 1989. Costs and Benefits of Phasing Out Production of CFCs and Halons in the United
States, Review Draft, Office of Air and Radiation, November 3, 1989.
U.S. EPA, 1989. ProspectforReducing Methane Emissions from U.S. Livestockby 2000. Internal U.S.
EPA memorandum from L Burke/OPPE. August 31, 1989.
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ATTACHMENT A
Data Developed to Prepare
Energy Component of CO 2
Reduction Cost Curve
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11-JuL-90 ACTUAL BASE CASE CHANGES IN 2000 DUE TO LOW 02’
1988 2000 C02 REDUCTION PROGRAMS CASE
ALLQUANTITIES ARE IN -
1O**15 BTU END-USE ELECTRICITY NATURAL GAS RENEWABLE
EPA CONSERVATION SUBSTITUTION SUBSTITUTION ENERGY
ResidentiaL
;i;;/LPG 1.61 1.35 -0.80 0.00 0.55
Gas 4.73 4.52 -2.08 0.80 3.24
CoaL 0.07 0.05 0.05
Etec. 3.01 3.79 -1.13 2.66
9.42 9.71 -3.21 0.00 0.00 0.00 6.50
Coimiericat
Resid 0.25 0.13 -0.13 0.00
Dist/LPG 0.71 0.81 -0.35 0.46
Gas 2.69 2.85 0 0.48 3.33
GasoLine 0.11 0.15 0.15
CoaL 0.11 0.10 0.10
ELec. 2.69 3.72 -1.08 2.65
6.56 7.76 -1.08 0.00 0.00 0.00 6:69
In striai
01st. 1.38 1.62 -0.24 1.38
LPG 1.6 2.06 2.06
GasoLine 0.22 0.26 0.26
Resid 0.74 0.55 -0.39 -0.01 0.15
Feedstocks 0.81 1.12 1.12
Other Petr. 3.72 3.58 3.58
Gas 7.38 8.60 1.79 0.61 11.00
Coat 1.69 1.84 -0.55 -0.36 0.93
Met. CoaL 1.08 0.95 0.95
ELec. 3.03 3.90 -0.22 -0.64 3 O4
Wood & Waste FueLs 0.17 0.23 0.23
21.82 24.71 -0.22 0.21 0.00 0.00 24.70
In-PLant Etec. Gen. 0.20 0.33
Transportation
Dist. 4.44 4.44 0.00 4.44
Jet 3.55 3.55 -0.04 3.51
GasoLine 14.4 14.40 -3.40 0.00 11.00
Resid 0.82 0.82 0.82
Nat. Gas 0.57 0.57 0.57
Other Petr. 0.29 0.52 0.52
Etec. 0.01 0.01 0.01
EthanoL 0.00 0.00 0.00 0.00
24.08 24.31 -3.44 0.00 0.00 0.00 20.87
ELectricity
0 1st. 0.11 0.15 0.15
Resid 1.21 0.80 0.80
Gas 2.92 6.06 -3.75 -0.99 5.50 -0.35 6.48
Coat 15.86 18.74 -3.75 -0.99 -5.50 -0.35 8.16
NucLear 5.64 6.80 0.00 6.80
Hydro/Renew/Other \1 2.69 3.40 0.70 4.10
Iuports 0.32 0.8 0.80
TotaL 28.73 36.75 -7.49 -1.97 0.00 0.00 26.49
DeLivered ELectricity 8.74 11.42 -2.43 -0.66 0.00 0.00 8.36
TotaL Primary Energy
OiL 35.97 36.31 -3.44 -0.39 -1.53 0.00 30.95
Gas 18.29 22.60 -5.82 0.80 7.39 -0.35 24.62
CoaL 18.79 21.68 -3.75 -1.54 -5.86 -0.35 10.19
NucLear 5.64 6.80 0.00 0.00 0.00 0.00 6.80
Hydro/Renew/Other 3.18 4.43 0.00 0.00 0.00 0.70 5.13
TotaL 81.87 91.82 -13.01 -1.12 -0.00 0.00 77.69
1. IncLudes utiLity hydro, wood generation, and non-industriaL OF generation.
-------
C: JB CO2tCO2F THOM .WK3
TEAR 2000 ESTIMATES
C02 REDUCTION OPTIONS
1 1-Ju l-90
02:17 PM
1. RESIDENTIAL
SHELL RETROFIT - GAS
SHELL RETROFIT - ELECTRIC
ELECTRIC APPLIANCES
GAS APPLIANCES - STEP
GAS APPLIANCES - STEP 2
GAS APPLIANCES - STEP 3
FUEL SUBSTITUTION - STEP 1
FUEL SUBSIITUTION - STEP 2
SECTOR TOTAL
2. CG4JIERCIAL
STEP 1
STEP 2
STEP 3
FUEL SUBSTITUTION - STEP I
FUEL SUBSTITUTION - STEP 2
SECTOR TOTAL
PROGRAM COSTS NET PROGRAM COSTS
S. R u a.
CAPTIAL OPERATING PSI (MIT FL L NET UNIT TOTAL
COSTS COSTS COSTS 2 SAVINGS COST COSTS
(11168$) (11188$) 68$/TI TU 88S/TI4OTU 88$/II4BTU ( 88$)
$4,925 0 1829 $15.58 -$7.29 44329
$2,150 0 $13.44 $15.56 -$2.14 4342
$6,055 0 $16.86 $15.58 $3.26 $1,054
$0 $0 $0.00 $0.30 40.30 439
$175 $0 $0.50 $2.80 -12.30 -$805
$13,306 $0 $8.56 $11.43 -$2.87 -$4,461
CARBON DISPLACED
Ru.. ... .Snn. Ss S Sa..n..n..fl..aa.u
PER UNIT TOTAL OJISJLATIVE COST PER
ENERGY SAVED DISPLACED DISPLACED IC HIIE
(KG/II4RTU) (10 6 NI) ( 106 NT) (88 lINT)
2. INDUSTRIAL
COGENERAT ION - STEP 1
COGENERATION - STEP 2
COGENERATIOM - STEP 3
COGENERAT 1011 - STEP 4
INDUSTRIAL HEAT PIJ4PS
FUEL SUBSTITUTION - STEP I
FUEL SUBSTITUTION - STEP 2
ELECTRIC MOTORS
SECTOR TOTAL
622 1,133 348
506 922 27?
75 137 4*
18.6 339 lOS
908 -561 348
36 0\1 0 0
250 I 0 0
220 679 679
2,5*7 2,649 1,798
$ 1, 507 $0 $L42 $3.56 -$1.13 -$705
$3,475 $0 $6.67 $3.49 $3.38 $1,709
$1,411 10 $16.81 $3.46 $15.33 $1,150
18,398 $0 $45.15 $3.57 $41.56 $7,734
$ 1,312 $0 $1.44 -$0. 17 $1.62 $ 1,470
$0 $0 $0.00 -12.30 $2.30 $828
$250 $0 $1.00 $0.80 10.20 $50
? $3572 . !:8
$16,353 $0 $5.23 -$0.51 $5.74 $17,940
37A 12.999 192.363 -$54.22
37.5 10.405 202.768 $164.25
37.9 1.542 204.310 $745.99
37.2 3.897 208.207 $1 984.46
2%.? 8.950 217.157 1164.23
*2.3 4.439 221.595 $186.54
7.0 1.740 223.335 $28.74
20.6 14.006 237.34* $561.0?
24.1 57.977 $309.43
ENERGY SAVINGS
•:S: as ,n: .: —_: —: fl3 5SS$Su•
ELECTRIC TOTAL
END-USE GENERATION PRIMARY
(l0 ’ 12 OTU) ( 10 12 BTU) (10 12 STU)
1,402 0 1,402 $19,334 $0 $13.79 $4.50 $9.29 $13 025 *4.5 20.259 20.259 $642.91
590 1,822 1,822 $2,744 $0 $4.65 $16.99 -$12.34 -$1 28* 206 37.562 57.82* -$193.83
54* 1,671 1,671 $3,100 $0 $5.73 $16.99 -$11.26 -$6,092 20.6 34.442 92263 -$176.87
45? 0 457 $1,878 $0 $4.11 $4.50 -10.39 -$178 *4.5 6.604 98867 -$26.99
2*8 0 218 $5,056 $0 $23.20 $4.50 $18.70 $4 077 *4.5 3.150 102.017 $1,294.12
0 0 0 10 $0 $0.00 14.50 -14.50 $0 0.0 0.000 102.017 $0.00
400 1 0 0 $200 $0 $0.50 $3.93 -$3.43 -$1,372 7.0 2.784 10480 1 -$492.82
400 I 0 0 $1,320 $0 $3.30 $3.93 -10.63 -$252 7.0 2.784 *07.585 -$9052
3,208 3,493 5,570 $33,633 $0 $8.39 $7.91 $0.46 $1,927 16.9 107.585 $17.91
594 1,834 1,834
*60 494 494
32* 991 99*
130\1 0 0
3 0 I 0 0
1,075 3,320 3,320
70.6 37.816 145.40* -$114.48
20.6 10.186 *5538? -$33.61
20.6 20.436 176.023 $51.58
7.0 0.905 176.928 -$43.10
7.0 2.436 *79.364 •$330A6
9 - 71.780 - 162.15
-------
C: %J8 CO2\CO2F INON.W53
YEAR 2000 ESTIMATES
C02 REDUCTION OPTIONS
3. TRANSPORTATION
tOy - STEP I
tOy - STEP 2
LDV - STEP 3
tOy - STEP 4
LOT - STEP I
LOT - STEP 2
LOT . STEP 3
LOT - STEP 6
HOT - STEP I
HOT - STEP 2
AIR TRANSPORTATION
ETHANOL SU8STITUTION
SECTOR TOTAL
4. ELECTRIC UTILITY
SOLAR - STEP I
SOLAR STEP 2
GEOTHERMAL
HYDRO - STEP 1
HYDRO - STEP 2
WIND - STEP 1
WIND - STEP 2
B I ONASS
IGCC
NUCLEAR
FUEL SUBSTITUTION - STEP I
FUEL SU8STITUTION - STEP 2
SECTOR TOTAL
ENERGY SAVINGS
U a: a a :0 : : : : . a a tsar: :: :22 * Baa e n. I . t o a ...
ELECTRIC TOTAL 1
E )-USE GENERATION PRIMARY
( 10 12 •TU) (T012 BTU) (I0 12 IIU)
TOTAL ALL SECTORS 10,261
1 Fuel sthstitul ion does not lead to energy sirings.
Sectoral totals do not Include fuel si.Lstltution quantities.
PROGRAM COSTS NET PROGRAM COSTS
ua4aaaue . .anea au a.. sue.. n .e . . . ..
!CAPTIAL OPERATING PER (MIT FUEL NET UNIV TOTAL
COSTS COSTS COSTS ‘ .2 SAVINGS COST COSTS
(III 88 1) (III 66 1) 88 $/PSTU 86 $/44RIU 88 $1448TU (NI 88 1)
1 1-Jul-90
02:17 PM
CARBON DISPLACED
PER UNIT TOTAL CTJIIJLATIVE COST PER
ENERGY SAVED DISPLACED DISPLACED TONNE
(EG/TISTU) (1026 NT) (106 NT) (88 S/NT)
151 0 151 -$522 $0 -$3.46 $8.24 -$11.70 -$1,767 21.4 3.233 260.574 -$546.47
1,358 0 1,356 $3,531 $0 $2.60 $8.26 -$5.64 -$7 659 21.4 29.015 269.649 -$263.43
302 0 302 $1,884 $0 $6.24 $8.24 -$2.00 -1604 21.4 6.466 276.115 -$93.41
236 0 236 $2,671 $0 $10.47 $8.24 $2.23 $526 21.4 5.053 281.168 $104.16
173 0 173 -$341 $0 -$1.97 $6.24 -$10.21 •$l,766 21.4 3.706 204.872 $476.88
72S 0 725 $1,216 $0 $1.68 $8.24 $6.S6 -$4,156 21.4 15.522 300.394 -$30640
667 0 447 $2 *95 $0 $4.91 16.24 -$3.33 •$I,489 21.4 9.570 309.964 -$155.53
10 0 10 1io $0 $10.34 $8.26 $2.14 $21 21.4 0.2*4 310.178 $99.95
0 0 0 $0 $0 $0.23 $7.16 -$4.91 $0 0.0 0.000 310.178 $0.00
0 0 0 $0 $0 $0.77 $7.16 $4.34 $0 0.0 0.000 310.178 $0.00
39 0 39 *126 $0 $3.23 $6.59 -$3.56 -$131 21.4 0.835 3*1.013 -$156.94
0 0 0 $0 $0 $10.79 $8.24 $2.SS $0 0.0 0.000 311.013 $0.00
3,44* 0 3,44* 10,665 $8.22 -$11,624 2I.4 73.672 -$239.22
0 0 0 $0 $0 $3.00 $0.00 10.00 $0 3.0 0.000 311.013 $000
0 0 0 $0 $0 $0.00 $0.00 $0.00 $0 0.0 0.000 311.013 $0.00
0 0 0 $0 $0 $0.00 $0.00 $0.00 $0 0.0 0.000 311.013 *0.00-
0 620 420 $535 $140 $1.61 $2.85 -$1.24 -$522 20.6 8.658 3*9.672 $60 29
0 0 0 $0 $0 $0.00 $0.00 $0.00 $0 0.0 0.000 319.672 $0.0O
0 276 276 $390 $263 $2.37 $2.85 -$0.48 -$134 20.6 5.690 325.361 -$25.48
0 0 0 $0 $0 $0.00 $0.00 $0.00 $0 0.0 0.000 525.361 $0.00
0 0 0 $0 $0 $0.00 $0.00 $0.00 $0 0.0 0.000 325.361 $0.00
0 0 0 *0 $0 $0.00 10.03 10.00 $0 0.0 0.000 325.361 $0.00
0 0 0 $0 $0 $0.00 *0.00 $0.00 $4) 0.0 0.000 325.361 $0.00
0 3,500 I 0 10 10 $0.00 -$2.33 $2.30 $8050 12.3 43.155 364.516 $18654
0 2,000 l 0 1600 *0 $3.30 -$2.30 $2.60 $5,200 *2.3 24.640 393.176 $210.87
0 696 696 $1,525 $403 *0:3 1 I.7Z 12:03 $12,594 0.0 82.163 $155.29
10,158 *4,825 $15,483 $403 $10,376 393.176 $26.39
¶,2 Except for the Electric UtIlity Sector, ts.it costs sr i cslcul.ted on an end-us. s.clor basIs.
-------
C; \JB\C02\CO2F INONWE3
YEAR 2000 ESTIMATES
C02 REDUCTION OPTIONS
ENERGY DISPLACED BY FUEL TYPE (TRILLION BTU)
•:gg_n: a_—n:z—_ _—:zt.cszcscsznz..aszazs.aggmacs 3: z:zc :ssc.s...zs.a.as.:na.. ,_ - -
END-USE ENERGY DISPLACED ELECTRIC GENERATION FUELS DISPLACED TOTAL PRIMARY ENERGY DISPLACED CLIISJLATIVE PRIMARY ENERGY DISPLACED
OIL GAS COAL (LEC TOTAL ELEC-OIL ELK-GAS ELK-COAL TOTAL OIL GAS COAL TOTAL OIL GAS L TOTAL
(T BTU) CT 8W) (T 8W) (I •TU) CT BTU) (I 8W) (T BTU) CT STU) (T SW) CT STU) C I SW) CTSTU) (TITU) - (ISTU) CT STU) CT STU) CT STU)
1. RESIDENTIAL
SHELL RETROFIT - GAS 0 1,402 0 0 1,402 0 0 0 0 0 *402 0 *402 0 1,402 0 1,402
SHELL RETROFIT - ELECTRIC 0 0 0 590 590 0 911 911 1.822 0 911 911 1.822 0 2,3*3 911 3,224
ELECTRIC APPLIANCES 0 0 0 541 541 0 835 635 1,671 0 635 635 1,671 0 3,146 1,746 4,595
GAS APPLIANCES - STEP 1 0 457 0 0 457 0 0 0 0 0 457 0 457 0 3605 1,746 5,352
GAS APPLIANCES - STEP 2 0 218 0 0 2*8 0 0 0 0 0 218 0 2*8 0 3,823 1,746 5,570
GAS APPLIANCES - STEP 3 0 0 0 0 0 0 0 0 0 0 o 0 0 0 3 .823 1,746 5,570
FUEL SUBSTITUTION - STEP 1 00 -400 0 0 0 0 0 0 0 400 -400 0 0 400 3,423 1,746 5,570
FUEL SUBSTITUTION - STEP 2 (00 -400 0 0 0 0 0 0 0 400 -400 0 0 800 3,023 1,746 5.570
SECTOR TOTAL 800 1,277 0 1,131 3.208 0 1,746 1,746 3,493 800 3,023 1 746 3570
2. CONMERCIAL
STEP * 0 0 0 594 594 0 9*7 9*7 1,834 0 917 917 1,834 800 3,94* 2,664 7,404
STEP 2 0 0 0 160 *60 0 247 247 494 0 247 247 494 800 4*68 2,9*1 7,698
STEP 3 0 0 0 32* 32* 0 496 496 991 0 496 496 991 600 4.683 3 406 8,890
FUEL SUBSTITUTION - STEP 1 130 -*30 0 0 0 0 0 0 0 *30 - I SO 0 0 930 4,553 3,406 8,890
FUEL SUBST!TUTION - STEP 2 so -350 - 0 0 - 0 0 0 350 -350 0 1,280 4,203 5,406 8.
SECTOR TOTAL 480 -460 0 1075 1075 0 I 6óO 1,660 3320 480 1,180 *660 3,320
2. INDUSTRIAL
COGENERATION- STEP I - *42 -927 0 367 -419 0 567 567 1.135 *42 -361 567 346 1,422 3,843 3,973 9,237
COGENERATION - STEP 2 *03 -748 0 299 -346 0 461 46* 922 *03 -287 461 277 1,525 3,556 4,434 9,5*4
COGENERATION - STEP 3 *6 -112 0 44 -52 0 66 66 137 *6 -44 68 4* 1,561 3,5*2 4,502 9.555
COGENERATION - STEP 4 42 -216 0 110 -126 0 *69 *69 339 42 -*07 169 lOS 1,583 3,405 4,672 9,660
INDUSTRIAL HEAT PtJ4PS 83 275 55* -182 728 0 -280 -280 -56* 83 -S 27* 348 1,666 3,400 4,942 10,005
FUEL SUBSTITUIION - STEP I 0 -360 360 0 0 0 0 0 0 0 -360 360 0 1,666 3,040 5,302 10,008
FUEL SUBSTITUTION - STEP 2 250 -250 0 0 0 0 0 0 0 2S0 -250 0 0 1.916 2,790 5,302 10,008
ELECTRIC MOTORS 0 0 0 220 220 0 340 340 619 0 340 340 619 1,916 3*30 5,642 *0,688
SECTOR TOTAL 636 -2.398 911 858 7 0 *325 1,325 2,649 636 -1,074 2,236 1 198
-------
C: JB\CO2\CO2F INON .WK3
YEAR 2000 ESTIMATES
C02 REDUCTION OPTIONS
3. TRANSPORTATION
LDV - STEP 1
LDV - STEP 2
LDV - STEP 3
LDV - STEP 4
LOT - STEP I
LOT - STEP 2
IDE - STEP 3
LOT . $ p 4
HOT - STEP I
HOT - STEP 2
AIR TRANSPORTATION
ETHANOL SUBSTITUTION
SECTOR TOTAL
4. ELECTRIC UTILITY
SOLAR - STEP I
SOLAR - STEP 2
GEOTHERMAL
HYDRO - STEP I
HYDRO - STEP 2
WIND - STEP I
WIND - STEP 2
8 IONASS
I CCC
NUCLEAR
FUEL SUBSTITUTION STEP I
FUEL SUBSTITUTION - STEP 2
SECTOR TOTAL
ENERGY DISPLACED ST FUEL TYPE (TRILLION $TU)
END-USE EMERGE DISPLACED ELECTRIC GENERATION FUELS DISPLACED TOTAL PRIMARY ENERGY DISPLACED D.ISRJLAIIVE PRIMARY ENERGY DISPLACED
OIL GAS COAL ELEC TOTAL ILIC-OIL ELIC-GAS UEC-COAL TOTAL OIL GAS L TOTAL OIL GAS COAL TOTAL
(I ITU) (T ITU) (1 STU) U STU) CT STU) (I SW) (T SW) (I STU) CT SW) (I SEW) (I STU) (T IIU) CT STU) (I STU) (T STU) CT STU) CT STU)
15* 0 0 0 151 0 0 0 0 151 0 0 151 2.067 3.130 S,M2 10,839
1.358 0 0 0 1,358 0 0 0 0 1,351 0 0 1,356 3,425 3,130- 5,642 17,197
302 0 0 0 302 0 0 0 0 302 0 0 302 3,127 3,130 1,642 12,499
236 0 0 0 236 0 0 0 0 236 0 0 236 3,963 3,130 1,642 12.735
IT S 0 0 0 ITS 0 0 0 0 173 0 0 ITS 4,136 3,130 5,642 12,908
725 0 0 0 725 0 0 0 0 725 0 0 725 4,661 3,130 5,642 13,633
447 0 0 0 447 0 0 0 0 447 0 0 467 5.308 3,130 5,642 14,080
10 0 0 0 tO 0 0 0 0 tO 0 0 10 S ,318 3,130 5,642 14,090
O 0 0 0 0 0 0 0 0 0 0 0 0 5,318 3,130 5,642 *6,090
O 0 0 0 0 0 0 0 0 0 0 0 0 1,318 3,130 5,642 16.090
39 0 0 0 39 0 0 0 0 39 0 0 39 5,3S7 3,130 5,642 16,129
O 0 0 0 0 0 0 0 0 0 0 0 0 5,357 3,130 5,642 14,129
3,441 0 0 0 3,461 . 0 0 0 0 3,441 0 0 3,441
O 0 0 0 0 0 0 0 0 0 0 0 0 5,357 3,130 S642 14,129
O 0 0 0 0 0 0 0 0 I 0 0 0 0 1,357 3,130 5,642 14,129
O 0 0, 0 0 0 0 0 0 0 0 0 0 1,351 3,130 5,642 14,129
0 0 0 0 0 0 710 210 420 0 210 210 420 1,357 3,340 5,852 14,549
0 0 0 0 0 0 0 0 0 0 0 0 0 5,357 3,360 5,652 14,549
0 0 0 0 0 0 138 136 776 0 136 138 276 1,357 3,478 5,990 14,625
0 0 0 0 0 0 0 0 0 0 0 0 0 1,357 3,478 5,990 14,625
0 0 0 o 0 0 0 0 0 0 0 0 0 5,357 3,678 5,990 14,625
O 0 0 0 0 0 0 0 0 0 0 0 0 5,357 3,678 5990 14,825
0 0 0 0 0 0 0 0 0 0 0 0 0 5,357 3,478 3,990 14,625
O 0 0 0 0 0 -3,500 3,500 0 0 -3,500 3,500 0 1,35? -22 9,490 16,625
O 0 0 0 0 0 -2,000 2,000 0 0 -7,000 2,000 0 5,357 •2 ,022 11,490 14,825
O 0 0 0 0 0 -5,152 3,648 696 0 -s 1Sz 1,648 696
TOTAL ALL SECTORS 5,357 -1,601 911 3,064 7,73;
0 -421 10,519 10,158 5,357 -7,022 11,490 16,825
-------
C:\J8 CO2 cO2F INON.WES
TEAR 2000 ESTIMATES
C02 REDUCTION OPtIONS
END-USE FUEL SHARES
OIL GAS COAL ELECTRIC
( I) ( I) ( 1) ( 1)
1. RESIDENTIAL
SHELL RETROFIT - GAS 0.0* 100.01
SHELL RETROFIT - ELECTRIC 0.0* 0.01
ELECTRIC APPLIANCES 0.01 0.01
GAS APPLIANCES - STEP 1 0.0* 100.01
GAS APPLIANCES STEP 2 0.01 too_ox
GAS APPLIANCES - StEP 3 0.0* 100.0*
FUEL SUBSTITUTION - STEP i too_ox -toooz
FUEL SUBSTITUTION - STEP 2 100.01 -too_ox
SECTOR TOTAL
2. C ERCIAL
STEP 1 - 0.01 Oo l
STEP 2 o.ox 0OZ
STEP 3 0.0* 0.01
FUEL SUBSTITUTION - STEP 1 100.01 -100.01
FUEl. SUBSTITUTION - STEP 2 100.01 -100.01
SECTOR TOTAL
o.ox too_ox
o.oz ioo.ox
0.01 100.0*
0.0* 0.01
0.0* 0.01
0.01 S00* 50.0*
0.01 50.01 50.0*
0.02 50.02 50.01
0.02 50.02 50.02
0.02 50.01 50.0*
2. INDUSTRIAL
COGENERATION - STEP I 22.82 -149.11
COGENERAT ION - STEP 2 20.6* -167.81
COGENERATION - STEP 3 21.3* -169.31
COGENERAT ION - STEP 4 22;6* -145.6*
INDUSTRIAL HEAT PU4PS 9.1* 30.31
FUEL SUBSTITUTION - STEP I 0.01 -100.01
FUEL SUBSTITUTION - STEP 2 too_ox -too.ox
ELECTRIC MOTORS 0.0* 0.01
0.02 59.02
0.01 59.01
0.01 59.0*
0.02 59.0*
60.71 20.O2.
100.0* 0.01
0.01 0.0*
0.0* 100.01
0.01 50.02 50.01
0.01 50.02 50.01
0.0* 50.02 50.01
0.01 50.0* 50.01
0.02 50.0* 50.01
0.02 50.01 50.02
0.01 50.0* 50.0*
0.02 50.0* 50.9*
0_ox 0.0*
0.01 100.02
0.0* 100.02
0.0* 0.0*
0.02 0.02
0.01 0.01
0.01 0.0*
0.01 0.02
ELECTRIC GENERAl ION FUEL SNARES
•flflSSO eS53CsS:tSSc.3
OIL GAS COAL
( I) ( I) ( I)
00* 50.01 50.01
0.01 50.02 50.01
0.0* 50.0* 50.0*
0.0* 50.02 50.01
00Z 50.02 50.01
0.01 50.01 5001
0.0* 50.02 50.01
0.0* 50.02 50.0*
SECTOR TOTAL
-------
C: JB\CO2 CO2F IN0N.I 3
YEAR 2000 ESTIMATES
C02 REDUCTION OPTIONS
(NO-USE TUEL SHARES
•SSfl . U UUSU2 c n n. . .. QCtUS33C .S.flS$US$$$.$..$..
ELECTRIC GENERATION TUEL SHARES
•USUSSUflt$$S5S SflflU
3. TRANSPORTATION
LOV STEP 1
1.02 - STEP 2
LDV - STEP 3
LDV - STEP 4
LOT - STEP I
LOT - STEP 2
LOT - STEP 3
LOT - STEP 4
HOT - STEP I
HOT - STEP 2
AIR TRANSPORTATION
ETHANOL SUBSTITUTION
SECTOR TOTAL
4. ELECTRIC UTILITY
SOLAR - STEP I
SOUR - STEP 2
GEOTHERMAL
HYDRO - SIEP I
HYDRO - STEP 2
WIND - STEP 1
WIND - STEP 2
B I cI4ASS
I GCC
NUCLEAR
YUEI. SUBSTITUTION - STEP I
TUEL SUBSTITUTION - STEP 2
0.08 0.02 0.0%
0.02 0.02 0.02
0.02 0.02 0.02
0.02 0.08 0.0%
0.02 0.08 0.0%
0.02 0.02 0.02
0.02 0.02 0.02
0.02 0.02 002
0.02 0.02 0.02
0.02 0.02 0.02
0.02 0.02 0.02
0.0% 0.02 0.02
0.02 0.08 0.02
0.02 0.02 0.02
0.02 0.02 0.08
0.02 S0.Q2 50.0%
0.02 0.02 0.08
0.02 50.02 50.02
0.02 0.0* 0.02
0.08 0.02 0.02
0.02 0.02 0.02
0.02 0.02 0.08
0.02 *00.02 *00.02
0.02 100.02 100.02
OIL GAS COAL ELECTRIC
(2) (8) (8) (8)
OIL GAS cW.L
(8) (2) (2)
100.08
0.08
0.02
0.08
0.08
50.02
50.02
100.02
0.08
0.08
0.02
0.08
30.02
50.08
100.02
0.02
0.02
0.02
0.02
50.08
50.02
100.02
0.08
0.02
0.02
0.02
50.08
50.02
*00.08
0.08
0.02
0.02
0.02
30.02
50.08
100.02
0.02
0.02
0.02
0.02
50.08
50.02
100.02
0.02
002
0.02
0.02
50.08
50.02
100.02
0.08
0.02
0.02
0.02
50.02
50.02
100.02
•
0.08
0.02
0.02
0.02
50.02
50.08
100.08
0.02
0.08
0.02
0.02
50.02
50.08
*00.08
0.02
0.08
0.02
0.02
50.02
50.02
100.02
0.02
0.0 1
0.02
0.02
0.02
0.0%
0.02
0.08
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.08
0.08
0.02
-------
C; J8 CO2 CO2F INON .WES
TEAR 2000 ESTIHATES
CO2 REDUCTION OPTIONS
I. RESIDENTIAL
SHELL RETROFIT GAS
SHELL RETROFIT ELECTRIC
ELECTRIC APPLIANCES
GAS APPLIANCES - STEP 1
GAS APPLIANCES - STEP 2
GAS APPLIANCES - SUP 3
FUEL SUBSTITUTION - STEP 1
FUEL SUBSTITUTION - STEP 2
SECTOR TOTAL
2. Cc *IERCIAL
STEP I
STEP 2
STEP!
FUEL SUBSTITUTION - STEP I
FUEL SUBSTITUTION - STEP 2
SECTOR TOTAL
$8.43
$4.50
$0.00
$16.99
$8.43
$4.50
$0.00
$16.99
$8.43
$4.50
$0.00
$16.99
$8.43
$4.50
$0.00
$16.99
$8.43
$4.50
$0.00
$16.99
$8.43
$4.50
$0.00
$16.99
$8.43
$4.50
$0.00
$16.99
$8.43
$4.50
$0.00
$16.99
$7.30 $4.50 $0.00 $15.58
$7.30 $4.50 $0.00 $15.58
$730 $4.50 $0.00 $15.58
$4.80 $4.50 $0.00 $15.58
$7.30 $4.50 $0.00 $15.58
$4.80
$4.80
$4.80
$4.80
$4.80
$4.80
$4.80
$4.80
$4.00
$4.00
$4.00
$4.00
$4.00
$4.00
$4.00
$4.00
$1.70
$1.70
$1.70
$1.70
$1.70
$1.70
$1.70
$1.70
$14.28
$14.28
$14.28
$14.28
$16.28
$14.28
$14.28
$14.28
FUEL PRICES
OIL GAS COAL ELECTRICITY
(88 $/II8lu)(88 $/ 11481U)(88 $/TSSBTU)(88 $/IsIBTu)
2. INDUSTRIAL
COGENERATION STEP 1
COGENERAT ION - STEP 2
COGENERAT ION - STEP 3
COGENERATION - STEP 4
INDUSTRIAL HEAT PTJ4PS
FUEL SUBSTITUTION - STEP I
FUEL SUBSTITUTION - STEP 2
ELECTRIC NOTORS
SECTOR TOTAL
-------
C: JB CO2 CO2F I NON .w 3
YEAR 2000 ESTIMATES
tO? REDUCTION OPTIONS
rL L pRices
•tflsa...sap..sn:g 3tSZSUSS$fl•
OIL GAS COAL ELCCTIICUV
(88 $/ 1148TU)(86 $/TSI8TU)(85 $/i 48lU)(55.$/is4aTu)
3. TRANSPORTATION
LDV STEP 1 $8.24 $4.00 $0.00 $16.99
CDV - STEP 2 $8.24 $4.00 $0.00 $16.99
L OV - STEP 3 $5.24 $4.00 $0.00 $16.99
CDV - STEP 6 $8.24 $4.00 $0.00 $16.99
LOT - STEP I $5.24 $4.00 $0.00 $16.99
CDT STEP 2 $8.24 $4.00 $0.00 $16.99
CD I - STEP 3 $5.24 $4.00 $0.00 $16.99
LOT . slip 4 $8.24 $4.00 $0.00 $16.99
HOT - STEP I $7.14 $4.00 $0.00 $16.99
HDT . STEP 2 $7.14 $4.00 $0.00 $16.99
AIR TRANSPORTATION 6.59 $4.00 $0.00 $16.99
ETHANOL SUBSTITUTION $5.24 $4.00 $0.00 $16.99
SECTOR TOTAL
4.. ELECTRIC UTILITY ‘
SOLAR STEP I $4.80 $4.00 $1.70
SOLAR - STEP 2 $4.80 $4.00 $1.70
GEOTHERMAL $4.80 $4.00 $1.70
HYDRO - STEP I $4.80 $4.00 $1.70
HYORO - STEP 2 $4.80 $4.00 $1.70
WIND - STEP I $4.80 $4.00 $1.70
WIND - SIEP 2 $4.80 $4.00 $1.70
BICB4ASS $4.80 $4.00 $1.70
IGCC $4.80 $4.00 $1.70
NUCLEAR 14.8.0 $4.00 $1.70
FUEL SUBSTITUTION STEP I $4.80 $4.00 $1.70
FUEL SUBSTITUTION - STEP 2 $4.80 $4.00 $1.70
-------
C: J8\CO2 CO 2 lNONWk3 1 1-Ju 1-90
02:17 PM
INPUT CONSTANIS
CARBON (MISSION
FACIONS
(G/4481U
OIL 21.41
GAS 14.4S
‘COAL 26.78
ELECTRIC
ELECTRICITY PRINART/ENO-USL RATIO 3.088
-------
11-Jul-90 BASE CASE CHANGES IN 2010 DUE TO LOW C02
2010 C02 REDUCTION PROGRAMS CASE
ALL QUANTITIES ARE IN
10**15 BTU END-USE’- ELECTRICITY NATURAL GAS RENEWABLE
EPA CONSERVATION SUBSTITUTIONSUBSTITUTION ENERGY
Residential
Dist/LPG 1.10 -0.80 0.00 0.30
Gas 4.70 -2.61 0.80 2.89
Coat 0.05 0.05
Etec. 4.56 -1.22 3.34
10.41 -3.84 0.00 0.00 0.00 6.57
ColTreri cat
Resid 0.10 -0.10 0.00
Dist/LPG 0.85 -0.38 0.47
Gas 2.60 0 0.48 3.08
GasoLine 0.15 0.15
Coat 0.10 0.10
Elec. 4.66 -1.31 3.35
- -
8.46 -1.31 0.00 0.00 0.00 7.15
In jstriaL
Dist. 1.90. -0.24 1.66
LPG 2.40 2.40
GasoLine 0.30 0.30
Resid 0.60 -0.39 -0.01 0.20
Feedstocks 1.40 1.40
Other Petr. 3.60 3.60
Gas 8.60 1.79 0.61 11.00
Coal 2.00 -0.55 -0.36 1.09
Met. Coat 0.60 0.60
ELec. 4.82 -0.30 -0.64 3,88
Wood & Waste Fuels 0.3 0.30
26.52 -0.30 0.21 0.00 0.00 26.43
In-Plant Etec. Gen. 0.69
Transpor ion
01st. 5.15 0.00 5.15
Jet 4.05 -0.10 3.96
GasoLine 15.61 -6.68 -0.89 8.04
Resid 0.99 0.99
Nat. Gas 0.61 0.61
Other Petr. 0.50 0.50
ELec. 0.01 0.01
Ethanol 0.00 0.89 0.89
26.92 -6.77 0.00 0.00 0.00 20.15
Electricity
Dist. 0.20 0.20
Resid 2.00 -1.20 0.80
Gas 5.78 -4.38 -0.99 9.00 -2.98 6.44
CoaL 26.00 -4.48 -0.99 -7.80 -2.98 9.76
NucLear 6.30 1.38 7.68
Hydro/Renew/Other \1 4.30 457 8.87
InVorts 0.8 0.80
Total 45.38 -8.86 -1.97 -0.00 0.00 33.75
Delivered ELectricity 14.05 -284 -0.64 0.00 0.00 10.58
Total Primary Energy
OiL 40.90 -6.77 -0.39 -2.73 -0.89 30.12
Gas 22.29 -6.99 0.80 10.89 -2.98 24.02
CoaL 28.75 -4.48 -1.54 -8.16 -2.98 11.60
NucLear 6.30 0.00 0.00 0.00 1.38 7.68
Hydro/Renewebtes/other 5.40 0.00 0.00 0.00 5.47 10.87
Total 103.64 -18.26 -1.12 0.00 0.00 84.28
1. IncLudes utility hydri. Includes utility hydro, wood generation, and non-industrial OF generation.
-------
C:\JB CO2\CO7FIW1N.UEl llJut-90
YEAR 2010 ESTIMATES 03:28 PM
C02 REDUCTION OPTIONS
1. RESIDENTIAL
SHELL RETROFIT - GAS
SHELL RETROFIT - ELECTRIC
ELECTRIC APPLIANCES
GAS APPLIANCES - STEP 1
GAS APPLIANCES - STEP 2
GAS APPLIANCES - STEP 3
FUEL SUBSTITUTION - STEP 1
FUEL SUBSTITUTION - SIEP 2
SECTOR TOTAL
2. CR4MERCIAL
STEP)
STEP 2
STEP 3
FUEL SUBSTITUTION STEP I
FUEL S&JBSTIIUTION - STEP 2
SECTOR TOTAL
2. INDUSTRIAL
COGENERATION - STEP 1
COGENERAT ION - STEP 2
COGENERATION STEP S
COGENERATION STEP 4
INDUSTRIAL HEAT PTJ4PS
FUEL SUBSTITUTION - STEP 1
FUEL SUBSIIIUTION STEP 2
ELECIRIC MOTORS
SECTOR TOTAL
ENERGY SAYINGS
PROGRAM COSIS NET PROGRAM COSTS
CARBON DISPLACED
C aS SS:s: saSSgS:: a::naaa: .aaSSzSzSs .c.
ass
sgssssasaasaaS a a asssasassassasa 5 a.. sSsa s a S aS:::ss aflC 5
5* 555 555 :s as....Cssa.5.fl.
ELECTRIC
TOTAL
CAPTIAL
OPERAUNG PEI UNIT FUEL NET UNIT
TOTAL
PER UNIT
TOTAL C*IIIJLATIVE COST PER
END-USE aNERATION
PRIMARY
COSTS
COSTS - COSTS 2 SAVINGS COST
COSTS
ENERGY SAVED
DISPLACED DISPLACED TONNE
(1D12 B IU) ( 1012 BTU)
( 1012 BTU)
(III 88 5)
1* 88 5) 88 S/b s1U 56 S/IStRTU U $/4 181u
( 6$ 5)
(EGflI4RTU)
( 106 NT) (106 NT) (U S/NT)
2,040 0
529 1,634
695 2,146
342 0
232 0
0 0
2,040
1,634
2,146
342
232
0
$30,233
$2.12?
34,601
$1,539
$4,452
$0
$0 $14.82 $5.50 $9.32
$0 $4.02 $18.16 -$14.14
$0 $6.62 $1 .16 -$11.54
$0 $4.50 $5.50 -$1.00
$0 $19.19 $5.50 $13.69
$0 $0.00 $5.50 -$5.50
*19.013
$7 ,453
-$8,020
-$342
$3,176
$0
16.5
20.6
20.6
14.5
14.5
0.0
29.478 29.478 $644.98
33.675 63.156 -$222.10
44.246 107.403 -$181.26
4.942 112.345 -*69.20
3.352 115.69? $947.40
0.000 115.697 $0.00
400 1 0
400 I 0
0
0
$200
$1320
$0 $0.50 $4.64 -$4.34
$0 $3.30 $4.64 -$1.54
-$1,736
-$616
7.0
1.0
2.784 1)6.481 -$623.56
2.784 121.265 -$221.26
3,838 3,780
6,394
$44,471
$0 $9.59 $5.73 $0.86
$3,995
0.0
121.265 .532.94
718 2 ,217
197 605
396 1.223
100 1 0
2,21?
605
1,223
0
*5.945
52,643
$7,470
$0
0 $5.26 $16.75 -$5.47
0 $13.42 $16.75 -$3.33
0 $15.56 $16.75 $2.11
$0 50.00 $0.20 -$0.20
-$6,051
-$657
$837
-$20
206
20.6
20.6
7.0
45.711 166.976 -$133.04
12.542 179.51$ -$52.37
25.211 204.728 $33.21
0.696 205.424 428.74
38.0 l 0
0
$115
$0 $0.46 $3.70 -$3.24
-$1,231
7.0
2.645 208.069 , -$465.44
1,311 4,049
4,049
$16233
$0 $9.06 $13.06 -$3.99
-$7,152
0.0
56.804 482.39
622 1,133
506 922
75 13?
186 339
908 -561
360 1 0
250 l 0
346
277
4 )
105
348
0
0
$1,507
$3,475
$1,411
$6398
$1,312
10
$250
$0 $2.42 $2.9? -$0.54
$0 $6.8? $2.59 $3.98
$0 $15.61 $2.8? 1*5.94
$0 $45.15 $2.99 , $42.16
$0 $1.44 -$0.02 $1.47
10 $0.00 -13.30 13.30
$0 $1.00 $0.70 $0.30
-$335
$2,012
$1195
$7,842
$1334
$1,158
$75
37.6
37.5
37.9”
37.2
25.7
12.3
7.0
12999 221.068 -$26.01
10.405 23 1473 $193.35
1.542 233.0)5 $775.41
3.897 236.9*2 2 012 36”
5.950 245.862 ‘ 1149.10
4.439 250.300 $267.34
1.740 252.040 $43.10
3 9
2,597 2,896
9
2,045
$ 0
$16,353
$0 .. °:°° !46
$0 $5.10 -$1.39 $6.49
$20,802
0.0
.. !:??! 271.140
63.070 $329.82
-------
C: JB’. ,CO2\CO2F ININ.WK*
YEAR 2010 ESTIMATES
C02 REDUCTION OPTIONS
\1 Fuel st.*>stilut ion does not lead to energy savings.
Sectorat totals do not Include fuel st stitution quentitlea.
1 1-Jul-90
03:28 PM
3. TRANSPORTATION
LDV - STEP 1
(DV - STEP 2
LDV STEP 3
(DV - STEP 4
LOT - STEP I
LOT STEP 2
LOT - STEP 3
LOT - STEP 4
HDT - STEPI
HOT - STEP 2
AIR TRANSPORTATION
ETHANOL SUBSTITUTION
SECTOR TOTAL
4. ELECTRIC UTILITY
SOLAR - STEP 1
SOLAR - STEP 2
GEOTHERMAL
HYDRO - STEP 1
HTDRO - STEP 2
WIND - STEP 1
WIND - STEP 2
B I OIASS
I GCC
NUCLEAR
FUEL SUBSTITUTION - STEP I
FUEl. SUBSTITUTION - STEP 2
SECTOR TOTAL
TOTAL ALL SECTORS
-$600
$3,516
$2,390
$2566
-$781
5*434
$2,880
$90
$0
$0
$307
$0
$11,802
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$7, 106
$7,106
-$2.53
$1.32
$3.86
$4.63
-$4.46
$0.87
13*0
$4.72
$0.00
$0.00
$3.23
$7.96
$2.47
ENERGY SAVINGS
cacccc..
ELECTRIC TOTAL
PROGRAM COSTS
•scast....,. ...flag.....n.....
CAPTIAL OPERATING PER UNIT
NET PROGRAM COSTS
Re flosses esteem
FUNL NET UNIT TOTAL
CARBON DISPLACED
•SflURSU R R R a as..s.acssa.s...
PER UNIT TOTAL C IJISJLATIVE ‘COST PER
END-USE GENERATION
PRIMARY
COSTS
COSTS COSTS 2
SAVINGS
COST
COSTS
ENERGY SAVED DISPLACED DISPLACED - TONNE
(l0 ’ 12 STU) (10 ’T2 BTU)
(lO ’ 12 BTU)
(11188 1)
(11186 5) 88 1!II TU
86 $/Ts 6TU
88$/IIIBTU
(11188 5)
(EG/IIISTU) (106 NT) (1O ’6 NT) (88 S/NT)
237 0
2,664 0
616 0
387 0
175 0
1648 0
929 0
19 0
237
2,664
616
387
175
1.648
929
19
•
•
$10.79
$10.79
$10.79
$10.79
$10.79
$10.79
$10.79
$10.79
-$13.32
-$9A7
-18.91
-$4.16
-1*5.25
-$9.92
-$7.69
-$4.07
-$3,157
-$25,228
-$4,257
-$1,610
-$2,669
-$16,348
‘$7 144
-1*ts
-$622.14
-$442.32
-$322.75
-$194.30
-$712.28
-$463.33
-$359.18
-$283.51
0 0
0 0
0
0
$6.65
$8.65
-$8.65
-1865
$0
$0
$0.00
$0.00
95 0
95
$6.52
-$5.29
-$503
-$247.06
893 0
7,663 0
- -. 893
7,663
110:19
•;
52.83
$6 29
- 565 ,357
-$132.18
-$387.39
0 828
0 276
0 690
0 840
0 420
0 552
o 276
0 690
0 100
0 1,380
0 7,000 I
0 2,000 I
828
276
690
840
420
552
276
690
100
1,380
0
0
$3,480
$3 160
1527
$1,070
$2660
$1,680
$3,240
$2,593
$1,916
$4,920
1.0
$600
$788 $5.15
$526 $13.36
$986 $2.19
$280 $1.61
$320 $7.10
$526 14.00
$526 $13.64
$482 $4.46
$2,970 $48.86
$1,950 $4.98
10 $0.00
$0 $030
$3.35
$3.35
$3.35
$3.35
$3.35
$3.35
$3.35
$3.55
$1.70
$3.35
-$2.61
-$3.30
$1.80
$10.01
-$1.16
-$1.74
$3.75
50.65
$10.29
$1.11
147.16
$1.63
$2.61
$3.60
$1,494
$2761
-1799
-$1,464
$ 1 573
1357
$2 84*
1764
$4,716
$2,247
$18,301
$7,200
20.6 11.069 452.274 $87.54
20.6 5.690 457.963 $485.33
20.6 14.224 472.188 -$56.14
20.6 17.317 489.504 -$8454
20.6 8658 498.163 $18168
20.6 11.379 509.542 $31.35
20.6 5.690 515.232 $499.39
20.6 14.224 529A56 $53.68
26.8 2.678 532.134 $1,761.02
20.6 26.449 560.583 ‘$78.98
11.4 79.867 640.450 $229.14
*2.3 26.660 665.110 $291.97
0 6,052
6,052
125,846
$9,354 $2.34
- 0.32
$266
$39,992
0.0 229.906 $173.95
4
15,409 16,777
26,203
$114,706
$16,462
-$5,922
865.1*0 -16.90
21.4
21.1.
21.4
21.4
21.4
21.4
2*.4
0.0
0.0
21.4
21.4
0.0
5.074
57. 036
13.189
8.286
3-747
35. 254
*9. 890
0.407
0.000
0.000
2.034
19. 119
*64.065
276.2 14
333. 250
346. 4 39
356.726
358. 471
393-755
‘13-us
614.051
414.051
4*4.051
4 16. 085
435.204
2 Except for the Electric UtilIty Sector, uisl coéta .rc calculated on wt end -ta. sector b.sis.
-------
C: JB\CO2\CO2F INII .1 1
YEAR 2010 ESTINATES
C02 REDUCTION OPTIONS
ENERGY DISPLACED ST FI.8L TYPE (TRILLION S W)
1. RESIDENTIAL
SHELL RETROFIT - GAS 0 2.040 0 0 2,040 0 0 0 0 0 2.040 0 2,040
SHELL RETROFIT - ELECTRIC 0 0 0 529 529 0 817 617 1.634 0 617 8*7 1,634
ELECTRIC APPLIANCES 0 0 0 695 695 0 1,073 1,073 2,146 0 1,073 1,073 2,146
GAS APPLIANCES - STEP 1 0 342 0 0 342 0 0 0 0 0 342 0 342
GAS APPLIANCES STEP 2 0 232 0 0 232 0 0 0 0 0 232 0 232
GAS APPLIANCES - STEPS 0 0 0 0 0 0 0 0 0 0 0 0 0
FUEL SUBSTITUTION - STEP I 400 -400 0 0- 0 0 0 0 0 400 -400 0 0
FUEL SUBSTITUTION - STEP 2 400 -400 0 0 0 0 0 0 0 400 -400 0 0
SECTOR TOTAL 800 1,814 0 1,224 3,835 0 1,890 1,890 3,780 800 3,704 1,890 6,394
2. CCRVIERCIAL
STEP 1 0 0 0 716 7*6 0 1,109 1,109 2,2*7 0 1,109 1,109 2,2*1 800 4,8*3 2,999 8,611
STEP 2 0 0 0 197 197 0 304 30 1. 606 0 304 306 606 800 5,117 3,303 9,220
STEPS 0 0 0 396 396 0 611 611 1,223 0 611 611 1,223 800 5,726 3,9*6 *0,443
FUEL SUBSTITUTION - STEP 1 100 -*00 0 0 0 0 0 0 0 *00 -*00 0 0 900 5,628 3,914 *0,443
FUEL SUBSTITUTION- STEP 2 380 -380 0 0 0 0 0 0 310 -350 0 0 1,280 5,248 3,9*4 10,443
SECTOR TOTAL 480 -480 0 131* 131* 0 .2,024 2,024 4,049 460 1,544 2,024 4.049
2. INDUSTRIAL
COGENERATION - STEP * 142 -927 0 367 -419 0 567 567 1,133 *42 -36* 561 348 1,422 4,888 4,48* *0,790
COGENERATION - STEP 2 103 -71.8 0 299 -346 0 46* 461 922 lO S -287 461 277 1,525 4,60* 4,942 11,068
COGENERATION - STEP 3 *6 -*12 0 44 52 0 68 68 137 *6 -44 65 4* 1,361 4,357 5,0*0 11,108
COGENERATION - STEP 4 42 -276 0 110 -121. 0 *69 169 339 42 -*07 *69 lOS 1,583 4,650 5,180 11,2*3
INDUSTRIAL HEAT PT)IPS 83 275 551 -182 728 0 -280 -280 -36* 83 -5 27* 346 1,664 4,445 5,45* 11,56*
FUEL SUBSTITUTION - STEP I 0 -360 360 0 0 0 0 0 0 0 -360 360 0 1,666 4,085 5,611 *1,56*
FUEL SUBSTITUTION - STEP 2 250 -250 0 0 0 0 0 0 0 250 -250 0 0 1,916 3,835 5,61* 11,56*
ELECTRIC NOTORS 0 0 0 300 300 0 463 463 926 0 463 463 926 1,9*6 4,296 6,274 *2,488
636 -2,398 911 938 87 0 1,445 1,448 2,896 636 -950 2,359 2,043
END-USE ENERGY DISPLACED ELECTRIC GENERATION FURLS DISPLACED TOTAL PRINART ENERGY DISPLACED QIWJLATIVE PRIMARY ENERGY DISPLACED
OIL GAS C04L ELEC TOTAL ILEC-OIL ELEC-GAS ELEC-COAL TOTAL OIL GAS COAL TOTAL OIL GAS C L TOTAL
CT OTU) CT STU) CT STU) CT STU) CT STU) CT STU) CT STU) (I STU) (I STU) CT ITO) CT STU) (I VU) (I STU) (T ITU) CT ITO) (I VU) CT STU)
0 2,040 0 2,040
0 2,857 6*7 3,674
0 3,930 1,690 5,820
0 6,272 1,890 6,162
0 6,504 1,890 6,394
0 4,506 1,690 6,394
400 4,106 1,890 6,394
800 3,704 1,890 6,396
SECTOR TOTAL
-------
C: J8\CO2\C02Fliu1N.W I
TEAR 2010 ESTIMAtES
C02 REDUCTION CPTIONS
ENERGY DISPLACED ST FUEL TYPE (TRILlION IIU)
. . .. .....
END-USE ENERGY DISPLACED ELECTRIC GENERATION FUELS DISPLACED TOTAL PRIMAl! ENERGY DISPLACED a..s1IATIvE P 5 111* 1! ENERGY DISPLACED
OIL GAS COAL 11CC TOTAL ELEC-OIL 11CC-GAS (tIC-COAL TOTAL OIL GAS COAL TOTAL OIL GAS COAL TOTAL
(T OTU) (I BTU) CT ITU) (1 STU) (1 STU) CT STU) CT STU) CT STU) (I SIU) (I STU) (I SIU) (I STU) (T STU) CT STU) (I STU) U MU) CT MU)
237 0 0 0 237 0 0 0 0 237 0 0 237 2*53 4,298 6.274 12.725
2,664 0 0 0 2,664 0 0 0 0 2,664 0 0 2,664 4.817 4.298 6,274 15,389
616 0 0 0 616 0 0 0 0 616 0 0 6*6 5,433 4,295 6,274 16,005
387 0 0 0 387 0 0 0 0 387 0 0 357 3,820 4,298 6,274 16,392
175 0 0 0 115 0 0 0 0 175 0 0 *75 5,995 4,298 6.274 16,567
1 .648 0 0 0 1,648 0 0 0 0 1,648 0 0 1,648 7,643 4,298 6,274 18,215
929 0 0 0 929 0 0 0 0 929 0 0 929 8,572 4,298 6,274 19,144
19 0 0 0 19 0 0 0 0 19 0 0 *9 6,59* 4,298 6,274 *9,163
O 0 0 0 0 0 o 0 0 0 0 0 0 8,59* 4,295 6,274 19,163
O 0 0 0 0 0 0 0 0 0 0 0 0 8,59* 4,295 6,274 19,163
95 0 0 0 95 0 0 0 0 95 0 0 95 8,666 4.298 6,276 *9,258
893 0 0 0 893 0 0 0 0 893 0 0 893 9.519 4,298 6,274 20,151
7,663 0 0 0 7,663 0 -- 0 0 0 7,663 0 0 1,663
4. ELECTRIC UTILITY
SOLAR -STEP I - 0 0 0 0 0 0 4*6 4*4 826 0 4*6 4*6 828 9,579 4,712 6,688 20,979
SOLAR - STEP 2 0 0 0 0 0 0 *31 *31 276 0 131 *35 276 9,579 - 4,850 6,826 21,255
GEOTHERMAL 0 0 0 0 0 0 345 345 690 0 345 345 690 9,579 5,195 7,171 21,945
HYDRO - STEP I 0 0 0 0 0 0 420 420 840 0 420 420 640 9,579 5,6*5 7,59* 22,785
HYDRO - STEP 2 0 0 0 0 0 0 210 2*0 420 0 210 210 420 9,579 5,825 7,80* 23,205
WIND - STEP 1 0 0 0 0 0 0 276 276 552 0 276 276 557 9,579 6,101 8,071 23,757
WIND - STEP 2 0 0 0 0 0 0 138 *38 276 0 *38 131 276 9,379 6,239 8,2*5 24,033
BIONASS 0 0 .0 0 0 0 345 345 690 0 345 343 690 9,579 6,584 8,560 26,723
IGCC 0 0 0 0 0 0 0 tOO *00 0 0 *00 100 9,579 6,584 8,660 24,823
NUCLEAR 0 0 0 0 0 0 690 690 1,380 0 690 690 1,350 9,579 7,274 9,350 26,203
FUEL SUBSTITUTION - STEP I 0 0 0 0 0 1,200 -7,000 3,800 0 1,200 -7,000 5,600 0 10,719 274 15,150 26,203
FUEL S*J8STITUTIOII-SIEP2 :2:00° 2,000 0 ,?0 0 .000 0 *0,719 -1,726 17,150 26,203
SECTOR TOTAL 0 0 0 0 0 1199.6 -4,826 *0,676 6,052 1,200 -6 026 10,676 6,052
TOTAL ALL SECTORS 9,579 -1,064 91* 3,475 *2,899 1,200 538 *6,239 *6,177 10,719 -1,726 11,150 26,203
3. TRANSPORTATION
LOV - STEP I
by - STEP 2
LDV - STEP 3
LDV - STEP 4
LOT - STEP I
LOT - STEP 2
LOT - STEP 3
LOT - STEP 4
HOT - STEP 1
HOT - STEP 2
AIR TRANSPORTATION
ETHANOL SUBSTITUTION
SECTOR TOTAL
-------
C: JB CO2\CO2F INlN.W I
YEAR 2010 ESTIMATES
C02 REDUCTION OPTIONS
END-USE FUEl. SHARES
:sz:zsa toctPSZtS .SC S.e$tSSSS .S .U
OIL GAS COAL ELECTRIC
(8) (8) (8) (2)
I. RESIDENTIAL
SHELL RETROFIT - GAS 0.02 100.02
SHELL RETROFIT - ELECTRIC 0.02 0.02
ELECTRIC APPLIANCES 0.02 0.02
GAS APPLIANCES STEP 1 002 *00.08
GAS APPLIANCES - STEP 2 0.02 *00.02
GAS APPLIANCES - STEP 3 0.02 *00.02
FUEL SUBSTITUTION - STEP I 100.01 -100.0%
FUEL SUBSTITUTION - SIEP 2 100.02 -100.02
SECTOR TOTAL
2. CCIII4ERCIAL
STEP I 0.08 0.02 0.0% 100.08 0.02 50.08 50.08
STEP 2 0.0% 0.08 0.02 *00.05 0.08 30.02 50.02
STEP 3 0.08 0.08 0.08 *00.08 0.02 30.08 50.02
FUEl. SUBSTITUTION - STEP I 100.08 -100.02 0.02 0.02 0.08 50.05 50.02
FUEl. SUBSTITUTION - STEP 2 100.08 -*00.08 0.02 0.02 0.05 50.02 50.08
SECTOR TOTAL
2. INDUSTRIAL
COGENERATION - STEP 1 22.88 -169.18 0.02 59.08 0.08 30.0% 50.02
COGENERATION STEP 2 20.4% -*67.68 0.08 59.01 0.08 50.08 50.02
COGENERATION - STEP 3 21.38 -169.3% 0.08 59.08 0.08 50.08 30.08
COGEWERATION - STEP 4 22.6% -168.48 0.08 59.08 0.02 50.08 50.08
INDUSTRIAL HEAT P(MPS 9.18 30.38 60.75 -20.05 0.02 50.08 50.0%
FUEL SUBSTITUTION - STEP I 0.08 -100.02 100.05 0.08 0.08 50.02 50.02
FUEL SUBSTITUTION - STEP 2 100.08 -*00.08 0.08 0.08 0.02 50.08 50.01
ELECTRIC MOTORS 0.08 0.08 0.02 100.08 0.08 50.02 50.9 2
0.05 0.02
0.08 100.02
0.0% *00.05
0.08 0.01
0.02 0.02
0.0% 0.08
0.02 0.08
0.08 0.08
ELECTRIC GENERATION FUEL SNARES
OIL GAS COAL
(8) (8) (8)
0.05 5002 50.08
0.02 50.02 50.02
0.02 50.08 50.08
0.02 50.05 50.08
0.02 50.02 50.08
0.05 50.08 50.05
0.08 50.02 50.08
0.08 50.02 50.08
SECTOR TOTAL
-------
C: JB\CO2 CO2F ININ.I l
YEAR 2010 ESTIMATES
CO2 REDUCTION OPTIONS
END-USE FUEL SHARES
C 88Z8fl5538 St8nnssz 8 CflflSStfl S*SSSIS
0.0%
0.0*
0.0%
0.02
0.01
0.02
0.01
0.0*
0.02
0.01
0.01
0.01
0.0%
0.0*
0.01
0.01
0.02
0.0*
0.02
0.0*
0.0*
0.0%
0.01
0.0*
0.0%
0.0%
0.0%
0.0%
0.0%
0.02
0.0%
0.02
0.01
0.0%
0.02
0.02
0.01
0.0%
0.0%
0.02
0.0%
0.0%
0.02
0.0%
0.0%
0.0%
0.02
0.0*
ELECTRIC GENERATION FUEL SNARES
OIL GAS CORL ELECTRIC
(1) (1) 1*) .
3.
TRANSPORTATION
LDV
STEP 1
100.02
0.0%
0.02
0.02
tOy
- STEP 2
100.02
0.0%
0.0%
0.02
LDV
- STEP 3
100.02
0.02
0.02
0.0%
LDV
- STEP 4
100.02
0.0%
0.02
0.0%
LOT
- STEP 1
100.02
0.0%
0.0%
0.0*
LOT
- STEP 2
100.0%
0.01
0.0*
0.01
LOT
- STEP 3
100.0%
0.02
0.0%
0.02
LOT
-: STEP 4
100.01
0.0%
0.0*
0.0%
H OT
STEP 1
100.0*
0.0%
0.02
0.0%
HOT
- STEP 2
100.0*
0.0*
0.01
0.02
AIR
TRANSPORTATION
100.0*
0.02
0.0%
0.0%
ETHANOL SUBSTITUTION
100.02
0.0%
0.0*
0.02
SECTOR TOTAL
4. ELECTRIC UTILITY
SOLAR - STEP 1
SOLAR - STEP 2
GEOTHERMAL
HYDRO - STEP 1
HYORO - STEP 2
WINO - STEP I
WIND - STEP 2
BIONASS
I GCC
NUCLEAR
FUEL SIJBSIIIUTION • STEP I
FUEL SUBSTITUTION - STEP 2
OIL GAS CW.L
(2) ( I) (2)
0.02 50.01 5002
0.0% 50.02 50.0%
0.0% 50.0% 30.0%
0.02 50.0% 30.0%
0.0% 50.02 30.0%
0.02 50.0% 50.02
0.02 50.02 50.02
0.02 50.0% 50.02
0.02 30.0% 50.0%
0.02 50.0% 50.0%
0.0% 30.02 50.0%
0.02 0.0% 0.02
0.02 50.02 50.0%
0.02 50.02 50.0%
0.0% 30.02 50.02
0.02 50.02 50.02
0.0% 30.0* 30.0%
0.02 50.0% 30.02
0.02 30.02 50.02
0.02 50.0% 50.02
0.02 0.0% 100.0%
0.0% 50.02 50.0%
$7.12 -100.01 82.92
0.02 -100.0* 100.02
-------
C;\JB CO2\CO2F ININ.WE1
YEAR 2010 ESTIMATES
C02 REDUCTION OPTIONS
1. RESIDENTIAL
SHELL RETROFIT - GAS
SHELL RETROFIT ELECTRIC
ELECTRIC APPLIANCES
GAS APPLIANCES - STEP 1
GAS APPLIANCES - STEP 2
GAS APPLIANCES - STEP 3
FUEL SUBSTITUTION - STEP I
FUEL SUBSTITUTION - STEP 2
SECTOR TOTAL
2. C *4ERCIAL
STEP 1
STEP 2
STEP 3
FUEL SU8STITUIION - STEP I
FUEL SUBSTITUTION - STEP 2
SECTOR TOTAL
2. INDUSTRIAL
COGENERATION - STEP 1
COGENERAIIO I - STEP 2
COGENERAT ION - STEP 3
COGENERATION - STEP 4
INDUSTRIAL HEAT PLI4PS
FUEL SUBSTITUTION - STEP I
FUEL SUBSTITUTION - STEP 2
ELECTRIC MOTORS
SECTOR TOTAL
FUEL PRICES
nas:sr_znncncsngae:aa an
OIL GAS COAL ELECTRICITY
(88 $IIR4BTU)(88 $/II4BTU)(M $/PI4ITU)(88 $/II4BTU)
$10.34
$5.50
$0.00
$18.16
$10.34
$5.50
$0.00
$18.16
$10.34
$5.50
$0.00
$18.16
$10.34
$5.50
$0.00
$18.16
$10.34
$5.50
$0.00
$18.16
$10.34
$5.50
$0.00
$18.16
$10.34
$5.50
$0.00
$18.16
$10.34
$5.50
10.00
$18.16
$9.20 $5.50 $0.00 $16.15
$9.20 $5.50 $0.00 $16.13
$9.20 $5.50 $0.00 $16.15
$5.70 $5.50 $0.00 $16.13
$9.20 $5.50 $0.00 $16.15
$5.70
$5.00
$1.70
$15.46
$5.70
$3.00
$1.70
$15.46
$5.70
$5.00
$1.10
$15.46
$5.70
$5.00
$1.70
$13.46
$5.70
$5.00
$1.70
$15.46
$3.70
$5.00
$1.70
$15.46
$5.70
$5.00
$1.10
$13.46
$S.70
$5.00
$1.70
$15.46
-------
C: JB CO2 Co2r ui1si.w I
YEAR 2010 ESTIMATES
C02 REDUCTION fl0NS
3. TRANSPORTATION
LDV - STEP I
LOV STEP 2
LDV - STEP 3
LDV STEP 4
LOT STEP I
LOT - STEP 2
LOT - STEP 3
LOT - STEP 4
HOT STEP 1
HDT - STEP 2
AIR TRANSPORTATION
ETHANOL SUBSTITUTION
SECTOR TOTAL
FUEL PRICES
sat*anacgssnsgz. flnsZzngzst:zuzt.t QUa
OIL GAS COAL ELECTRICITY
CU $1 1e48Tu)(88 S/I4BTU)(88 $/IS48TU)(8a $/ISIBTU)
$10.79 $5.00 $0.00 $18.16
$10.79 $5.00 $0.00 $18.16
$10.79 $5.00 $0.00 $18.16
$10.79 $5.00 $0.00 $18.16
$10.79 $5.00 $0.00 $18.16
$10.79 $5.00 $0.00 $18.16
$10.19 $5.00 $0.00 $18.16
$10.79 $5.00 S000 $18.16
$8.65 $5.00 $0.00 $18.16
$8.65 85.00 $0.00 $18.16
$8.52 $5.00 $0.00 $18.16
$10.79 $5.00 $0.00 $18.16
4. ELECTRIC UTILITY
SOLAR STEP I $5.70
SOLAR STEP 2 $5.70
GEOTHERMAL $5.10
HYDRa - STEP I $5.70
HYDRO - STEP 2 $5.70
WIND - STEP I $5.70
WIND - STEP 2 $5.70
BIONASS $5.70
16CC $5.70
NUCLEAR $5.70
FUEL SUBSTITUTION STEP I 85.70
FUEL SUBSTITUTION - STEP 2 $5.70
$5.00
$5.00
$5.00
$5.00
$5.00
$5.00
$5.00
$5.00
$5.00
$5.00
$5.00
$5.00
$1.70
$1.10
$1.70
$1.70
$1.70
$1.70
$1.70
$1.70
$1.70
$1.70
$1.70
$1.70
-------
C: JB CO2 CO2IIN1 N. 1 il-Jut-gO
03:28 PN
INPW CONSTANTS
CARSON (MISSION
PACTO RS
KG/*SIU
OIL 21.41
GAS 14.45
COAL 26.78
ELECTRIC
ELECTRICITY PRIMARY/END-USE RATIO 3.088
-------
ATTACHMENT B
ACEEE Report on Light Di4y
Vehicles and Trucks
06W0658C
-------
SUPPLX CURVES OF CONSERVED ENERGY
FOR AUTOMOBILES
DRAFT
Prepared for:
Lawrence Berkeley Laboratory
Applied Science Division
Berkeley. California
Prepared by:
Marc Ledbetter
American Council for an Energy-Efficient Economy
Marc Ross
University of Michigan, Department of Physics
American Council for an Energy-Efficient Economy
December, 1989
-------
DRAFT
This report analyzes the cost effectiveness of automobile
fuel economy technologies and the fuel savings that could result
from their widespread use in the U.S. automobile fleet.
Estimates are derived for the years 2000 and 2010. The
technologies analyzed here do not exhaust the list of
technologies that may be available for improving fuel economy.
This is.especially true for the 2010 estimates. If policies to
push fuel. economy to substantially higher than current levels are
enacted, new fuel economy technologies will surely be developed.
This analysis thus represents the technological potential for
technologies that are already relatively well understood. Supply
curves of conserved energy are developed to illustrate the
results of the analysis.
COSTS OF TECHNOLOGIES
Developing a supply curve of conserved energy for light
vehicles is difficult at best, largely because cost information
on light vehicle technologies is very difficult to obtain.
Automobile manufacturers consider the information proprietary and
therefore withhold it. For many fuel economy improvements and
technologies, manufacturers themselves don’t ‘even have reasonable
estimates of their costs. Furthermore, technologies that improve’
fuel economy often have benefits that serve other purposes. For
• example, multi—point fuel injection improves fuel economy, but it
1
-------
DRAFT
• also decreases emissions and improves performance. Such multi-
purpose benefits make it difficult to determine how much of the
total cost of a technology should be allocated to fuel economy.
Even further complications arise in trying to adjust costs for
retooling expenses, amortization periods, and manufacturer
markup.
Despite these and other unspecified difficulties, Energy and
Environmental Analysis, Inc.(EEA), Arlington, VA, has compiled a
set of cost estimates for fuel, economy technologies that the U.S.
Department of Energy uses to analyze fuel economy policies.
These cost estimates and related information have recently
appeared in several publications. 1 Given the amount of scrutiny
and revisions these numbers have been subjected to, and given the
difficulty in developing alternative estimates of costs, this
analysis relies heavily on the cost estimates derived by EEA.
EEA derived its costs using “normal costing,” that is,
estimates of variable manufacturing costs for each technology
were multiplied by an estimate of an industry’ average ratio
between variable costs and retail vehicle prices to determine
consumer cost. Costs used in this analysis are thus estimates of
the change in consumer car prices that would result from use of
these technologies.
2
-------
DRAFT
Despite the care taken in development of EEA’s cost
estimates, the reader is cautioned not to consider these numbers
to be firm. These are reasonable estimates, given the
difficulties and inaccuracies encountered in compiling these
kinds of numbers. For fuel economy technologies that are pieces
of equipment added to a car, such as fuel injection, costs are
more easily determined. As noted above, however, if.this
equipment serves more than one purpose, the portion of the
equipment costs that should be allocated to fuel economy is still
difficult to determine and subjective. For fuel economy
technologies that are simply a new way of building an existing
part of the car and require little or no extra materials, such as
aerodynamic improvements, costs are more difficult to determine;
and often times, the costs for these technologies essentially
disappear over time.
As mentioned above, this analysis relies heavily on EEA’s
cost data.. Substantial adjustments, however, were made in these
cost estimates for the part of the analysis projecting to the
year 2010. In this part, the costs for several technologies were
adjusted downward to reflect the high likelihood that some
technologies, including those with which the auto industry has
little manufacturing experience, will become cheaper. Refer to
Tables 2-5 for all cost data.
3
-------
DRAFT
Arguments will, undoubtedly ensue over whether the costs used
in this analysis are too high or too low. These arguments,
however, probably won’t have any firmer basis than the cost
estimates used here.
TECHNOLOGIES ANALYZED
Pour supply curves of conserved energy are developed in this
analysis. Two time horizons are used —— 2000 and 2010 for
each of two technology groups.
Technology Group 1 is limited to those technologies
appearing in Diflgiio, et. al. 2 (See Table 1) According to
Difiglio, et. al., these technologies are proven technologies
that are already available in existing cars or prototypes; other
technologies were omitted because, “1) they are not rnarket
ready, or 2) they do not presently meet vehicle emission
standards, or 3) they detract significantly from performance,
ride, or capacity, or in some other way are not acceptable to
consumers. Furthermore, the selected technologies “would not
reduce performance, ride, or capacity over 1987 levels.”
Estimates of fuel economy improvement associated with each of
these technologies are the same or are very similar to those used
in Difiglio, et. al. Some small adjustments were made to make
those estimates consistent with the methodology used here. In
4
-------
DRAFT
sum, Technology Group 1 is a close approximation of the
technologies and their associated fuel savings used in Difiglio,
et. a]..
Technology Group 2 includes all the technologies in Group 1,
plus idle off and aggressive transmission management. These two
technologies were not included in the list analyzed by Difiglio,
et. al. These technologies are included in this analysis because
they offer significant potential for improving fuel economy,
could ‘be installed in production vehicles before 2000, and
because they, like other technologies in this group, do not
significantly degrade ride, performance, or capacity over 1987
levels.
These two additional technologies included in Group 2 will
change the feel of driving a car. For example, more gear
shifting will occur with aggressive transmission management and a
car will operate in higher gears more of the time, causing a
slight delay for downshifts needed to accelerate quickly.
(Electronic transmission control can minimize the effect these
changes will have on the driving feel.) The Continuously
Variable Transmission included in’ Technology Group 1 would also
change driving, feel. The Technology Descriptions section
describes each of the technologies in Technology Groups 1 and 2.
5
-------
DRAFT
METHODOLOGY
Al . ]. curves are calculated from a base year of 1987, i.e.,
improvements in fuel, economy and costs are relative to 1987
levels. (The average nominal, or EPA—rated, fuel economy of all
domestic and import new cars sold in the United States in 1987
was 28.3 mpg.). The average interior volume, performance levels,
and cargo capacities (for light trucks) are held at their 1987
levels .
The technologies and costs used in developing the Year 2000
Automobile Fuel Economy Supply Curves are listed in Tables 1-4.
(A key to the acronyms used to identify the technologies follows
in Table 2.) Fifteen separate technologies are listed, some of
which are combinations of technologies (e.g., TRANS represents
electronic transmission control and torque converter lock up),
and some of which aren’t technologies in the sense of new devices
or equipment (e.g.. aerodynamic improvements represent an
advancement in design, not a new technology).
The consumer costs estimated for each of these technologies
are listed in the second column of the table (CONSUMER COST), and
are annualized in the third column (ANNUAL COST) using a 7%
discount rate, a ten year estimated useful. life, and a
distribution for miles driven per year, by car vintage, as
6
-------
DRAFT
estimated by the U.S. Department of Transportation. 4 The costs
for the year 2000 curves approximate costs developed by LEA (with
the exception of the costs for idle off and aggressive
transmission management, which were independently estimated).
The costs for the year 2010 curves are similar, but some were
adjusted downward to reflect the substantial likelihood that real
costs for many of these technologies will fall over time, as
manufacturing and design experience are gained. Estimates of the
fuel economy increase that could be achieved with all but two
technologies were also derived from Difiglio, et. al. 5 (These
estimates are listed in INDIVID NEW CAR S MPG INCR and INDIVID
CAR MPG INCR.) The fuel economy increase associated with two
technologies, aggressive transmission management and idle off,
were independently estimated by the authors. 6
These estimates and all other estimates of fuel economy in
Tables 1—4 are estimates of actual, on—road fuel economy,
calculated by adjusting EPA-rated combined city/highway fuel
economy to account for its growing over—estimation of actual fuel
economy. The EPA fuel economy test procedure substantially over-
estimates on—road fuel economy because of differences between the
official EPA driving cycle and actual driving conditions.
Increased urban congestion, higher highway speeds, and a larger
fraction of total miles being driven in urban areas are projected
to increase the difference between EPA fuel economy and actual
7
-------
DRAFT
fuel economy from 15% in’1987 to 30% in 2010. Based on this
estimate, year 2000 fuel economy levels in this analysis are 23%
below the EPA—rated level, and year 2010 estimates are 30% below.
Values in the sixth column in Tables 1-4, NEW CAR FLEET MPG
INCR, were determined by estimating the extent to which each new
technology could penetrate the new car fleet by the year 2000.
(The ratio of NEW CAR FLEET MPG INCR to INDIVID NEW CAR MPG INCR
reveals the estimated increase in penetration of each
technology.) These estimates were derived from Difiglio, et.
a ]., and other government and industry sources. Penetration
levels taken from Difiglio, at. al. were taken from their maximum
technology scenario because the authors felt these rates of new
technology penetration better reflect the rapidly changing
automotive industry, where competitive pressures are forcing
manufacturers to redesign car lines more rapidly than in the
past.
The cost of conserved energy, CCE/MMBTU was calculated using
a 7% real discount rate and miles driven per year, by vintage, as
specified by the U.S. Department of Transportation. 8 The values
in this column can roughly be regarded as the societal cost
effectiveness of adopting the specified technologies. The Energy
Information Administration projects gasoline prices to rise to
$10.56 per million Btu ($1.32 per gallon) by 2000. Thus, all
8
-------
DRAFT
technologies with lower costs are deemed cost effective.
A truer test of societal cost effectiveness would value gasoline
at a higher level, to include such things as the environmental,
security, and health costs of consuming gasoline.
The fuel savings associated with each technology are based
on the assumption that automobile miles traveled in the United
States grow at the rate of 2.5% per year to the year 2000, and 2%
per year to the year 2010.. These estimates are also based on
the ;assumption that--each-technology is phased into the new car
fleet at a steady, straight-line rate over the period 1992 to
2000. Energy savings estimates for the year 2010do not assume a
higher rate of penetration of these technologies in new cars by
the year 2010 (a high degree of penetration in the new car fleet
is already achieved by the year 2000). The year 2010 savings
estimates, however, are based on higher penetration of these
technologies into the entire vehicle fleet, i.e., the new cars
with these technologies will comprise a large fraction of all
vehicles on the road in the year 2010. The extent to which each
technology is phased in varies by technology, and is captured in
the sixth column, NEW CAR FLEET MPG INCR.
The results of Table 1-4 appear in Figures 1-4. The supply
curves in Figure 1-4 estimate how much fuel could be saved in the
year 2000 or 2010 (horizon -tal axis), the cost of achieving this
9
-------
DRAFT
level of savings (vertical axis), and the least costly
combination of fuel economy technologies that would be used to
achieve this level of savings. Each step on these curves
represents a technology from Tables 1—4, and reveals the cost of
the technology, and the potential savings associated from its
adoption.
The reader is also cautioned to note that the levels of fuel.
economy deemed cost—effective here assume that automobile size
and acceleration performance are held constant at their 1987
levels. Since both performance and size have increased slightly
since then, this analysis assumes a small reduction of vehicle
size and acceleration performance. Also worthy of note is the
trade off between vehicle performance and fuel economy.
Increasing performance has a negative effect on fuel economy. A
recent EPA analysis concluded that the decrease in the average 0
to 60 miles per hour acceleration rating —— from 14.4 seconds in
1982 to 12.5 seconds in 1989 -- has caused a 2 MPG decline in the
average fuel economy of new cars. Thus, the fact that existing
use of many of these technologies hasn’t produced the fuel.
economy gain identified here doesn’t disprove these estimates of
fuel. economy potential. In fact, many of these technologies are
now being used to enhance performance rather than fuel economy.
10
-------
DRAFT
RESULTS
Care should be taken in interpreting the results of the
supply curves developed here. The order in which these curves
suggest technologies be adopted is not necessarily ideal or
reasonable. Schedules for vehicle redesign and introduction,
amortization schedules for capital equipment, and other industry
characteristics will probably dictate a different order of
adoption. Furthermore, other technologies not considered in the
development of this curve are likely to become feasible and cost
effective by the year 2000. especially if the federal government
mandates substantial fuel economy improvements in automobiles.
These curves should only be interpreted to provide a general idea
of the range and kinds of technologies that may be cost effective
for improving fuel economy.
Supply Curves for the Year 2000 (Figures 1 and 2)
As seen in Figure 1, the mix of fuel economy technologies
and their costs considered here yields cost—effective fuel
savings in the year 2000 of about 2.1 quads (quadrillion, 1015,
Btu). The savings associated with technologies on the curve
11
-------
DRAFT’
Table 1
KEY TOTECHNOLIOGIES LISTED IN TABLES 2-5
(Technology Groups 1 and 2)
IVC — Intake Valve Control
RCF — Roller Cam Followers
MPFI - Multi-point Fuel Injection
4V - Four Valves per Cylinder Engines
AERO - Aerodynamic Improvements
TRANS — Torque Converter Lockup and Electronic Transmission
Control (Group 1 only)
TCLU - Torque Converter Lockup (Group 2 only)
OHC - Overhead Cam Engine
FWD - Front Wheel Drive
CVT — Continuously Variable Transmission
ACCES — Improved Accessories, including Electric Power Steering
ADV F — Engine Friction Reduction
5AOD - Five—Speed Automatic Overdrive Transmission
LUB/T - Improved Lubrication and Tires
WT RED - Weight Reduction
TIRES - Advanced Tires (Improvements Beyond that included in
LUB/T)
TRANS MAN - Aggressive Transmission Management (Group 2 only)
IDLE OFF - Idle of f (Group 2 only)
• KEY TO COLUMN HEADINGS IN TABLES 2-5
TECHNOLOGY - Fuel economy technology (or measure)
CONSUMER COST - Retail cost of each technology, per car
ANNUAL COST - Retail cost of each technology, annualized over
ten year period at 7% discount rate
INDIVID NEW CAR S MPG INCR - S increase in fuel economy
attributable to each technology
INDIVID CAR MPG INCR - Result of applying S in INDIVID NEW CAR %
MPG INCR to previous new car fleet fuel economy level in NEW
CAR FLT MPG
NEW CAR FLEET MPG INCR. - Estimate of how much the technology can
increase the new car fleet mpg, taking into account INDIVID
CAR MPG INCR and the potential for increasing the
technology’s penetration into the new car fleet
NEW CAR FLIT MPG — Fuel economy of new car fleet (adjusted on-
road mpg), after adoption of specified technology
CCE/MMBTU - Cost of conserved energy from technology, per million
Btu saved
2000 (2010) FLEET MPG — Average fuel economy of all cars on road,
given new car fleet cumulative adoption of specified
technologies; all technologies phased in with straight-line
increase to the year 2000 (2010)
2000 (2010) SAVINGS MMBTU — Energy savings in the year 2000
12
-------
Table 2
CONSERVATION SUPPLY CURVE, AUTO FUEL EFVICI NCY
TECHNOLOGY GROUP 1
SAVINGS IN 2000
INDIVID
INDIVID
NEW
•
N2W
CAR
FUEL./
FLEET
TECHNOLOGY
CONSUMER
COST-$
ANNUAL
COST
NEW
MPG
CAR S
INCR
NEW
MPG
CAR
INCR
FLEET
MPG INCR
FIT
MPG
MMBTU
MPG
QUAD. BTU
-
BASE, 1987
21.7
21.8
1.49
21.64
21.70
0.030
1
‘RCF
11
1.51
1.5
0.33
0.12
1.78
22.60
0.382
2
IVC
80
10.96
.10.0
2.18
1.64
23.5
24.4
2.66
23.09
0.196
3
AERO
54
7.40
4.6
1.08
0.92
2.97
23.95
0.328
4
4V
84
11.51
6,8
1.66
1.66
26.0
27.1
3.15
24.50
0.196
5
OHC
74
10.1 4
6 O
1.56
1.08
0.62
27.7
4.14
24.82
0.108
6
FWD
150
20.55
10.0
2.71
4.45
25.00
0.064
7
ACCESS
29
3.97
.1.7
0.47
0.38
.
28.6
4.71
25.25
0.081
8
TRANS
39
5.34
.2
0.62
0.49
0.56
29.2
5.24
25.53
0.090
9
MPFI
67
9.18
3.5
1.00
5.61
25.98
0.143
10
ADV FRIC
80
10.96
4.0
1.17
0.93
.
•
30.1
6.20
26.29
0.094
11
CVT
100
13.70
4.7
1.41
0.64
6.32
26.43
0.044
12
LUB/TIRE
22
3.01
1.0
0.31
0.31
32.8
8.81
27.25
0.239
13
NT RED
190
26.03
6.6
2.05
1.74
10.13
27.54
0.080
14
5AOD
150
20.55
4.7
1.54
0.62
12.42
27.62
0.021
15
TIRES II
20
2.74
0.5
0.17
0.17
2.096
-------
Figure 1
Conservation Supply Curve
Auto Fuel Efficiency, Year 2000
Technology Group 1
Cost per Million BTU Saved (1988$)
16.00
14.00
12.00
10.00
8.00
6.00
4.00
2.00
0.00
0 0.5
1 1.5 2 2.5
Quadrillion BTUs of Fuel Saved
3.5
Assumes 7 Discount Rate
-------
Table 3
CONSERVATION ZUPPLY CURVE, AUTO FUEL EFFICIENCY
TECHNOLOGY GROUP 2
SAVINGS IN 2000
INDIVID INDIVID
CONSUMER ANNUAL NEW CAR % NEW CAR
TECHNOLOGY COST-S COST MPG INCR MPG INCR
NEW CAR
FLEET
MPG INCR
COST
FUEL/
FLEET
Saving8
NEW CAR
MMBTU
MPG
QUALL BTU
BASE, 1987
. ‘
23.3
1.32.
22.5
0.383
1
TRANS MAN
60
8.22
10
2.17
1.63
0.13
23.5
1.61
22.6
0.029
2
RCF
11
1.51
1.5
0.35
25.2
1.91
23.5
0.367
3
IVC
80
10.96
10.0
2.35
1.76
2.40
23.6
0.024
4
TCLU
35
4.80
3.0
0.76
0.12
26.3
2.88
24.1
0.188
5
AERO
54
7.40
4.6
1.17
0.99
27.8
2.95
24.8
0.256
6
IDLE OFF
120
16.44
11.0
2.90
1.45
29.7
•
3.39
25.8
0.305
7
4V
84
11.51
6.8
1.89
1.89
3.59
26.4
0.183
8
OHC
74
10.14
6.0
1.78
1.23
30.9
.
4.71
26.7
0.101
9
FWD
150
20.55
10.0
3.09
.Z t
0.71
32.0
5.07
26.9
0.059
10
ACCESS
29
3.97
1.7
0.54
5.87
27.2
0.084
11
MPFI
67
9.18
3.5
1.12
0.63
33.7
6.28
27.7
0.135
12
ADV FRIC
80
10.96
4.0
.1.31
1.05
6.94
28.0
0.088
13
CVT
100
13.70
4.7
1.58
0.71
7.07
28.2
0.042
14
LUB/TIRE
22
3.01
1.0
0.34
0.34
9.87
29.0
0.224
15
NT RED
190
26.03
6.6
-
2.29
1.95
37.4
11.35
29.3
0.075
16
5AOD
150
20.55
4.7
0.5
1.73
0.69
13.91
29.4
0.020
17
TIRES II
20
2.74
0.19
0.19
7
I ,’
I,)
L
Lj: ..
‘•1
fI•
7
-------
4.00
Figure 2
Conservation Supply Curve
Auto Fuel Efficie icy, Year 2000
Technology Group 2
Cost per Million BTU Saved (1988$)
0 0.5
1 1.5 2 2.5
Quadrillion ETUs of Fuel Saved
16.00
14.00
12.00
10.00
8.00
*10.56
6.00
2.00
0.00
2.5 Quads
3
3.5
Assumes 77 Discount Rate
-------
Table 4
COHSERVATION SUPPLY CURVE, AUTO FUEL EFFICIENCY
TECHNOLOGY GROUP 1
SAVINGS IN 2010
INDIVID
CONSUMER ANNUAL NEW CAR %
TECHNOLOGY COST-S COST MPG INCR
INDIVID
NEW CAR
MPG INCR
NEW CAR
FLEET
MPG INCR
NEW CAR
FUEL/
FLEET
S vings
FLT MPG MHBTU
MPG
QUAD. BTU
BASE, 1987
,
1.35
21.1
0.00
21.1
0.801
1
4V
0
0.00
6.8
0.83
22.0
1.20
21.9
0.444
2
AERO
27
3.70
4.6
0.97
0.12
22.1
1.51
22.0
.0.063
3
RCF
11
1.51
1.5
0.33
1.66
.
23.8
1.80
23.6
0.789
4
IVC
80
10.96
10.0
2.21
0.40
•
0.32
24.1
1.97
24.0
0.141
5
ACCESS
15
2.06
1.7
0.77
24.8
2.32.
24.7
0.323
6
ADV FRIC
40
5.48
4.0
0.96
0.25
25.1
2.55
24.9
0.100
7
LIJE/TIRE
11
1.51
1.0
0.25
1.18
0.53
25.6
2.59
‘
25.5
0.207
8
CVT
50
6.85
4.7
1.06
26.7
3.10
26.5
0.389
9
OHC
74
10.14
6.0
1.54
0.61
27.3
4.07
27.1
0.212
10
FWD
150
20.55
10.0
0.96
0.54
27.8
4.18
27.6
0.177
11
MPFI
56
7.67
3.5
0.46
28.3
4.29
28.0
0.147
12
TRANS
39
5.34
2.2
0.61
1.59
29.9
5.22
29.6
0.472
13
WT RED
130
17.81
6.6
1.97
0.56
30.4
6.16
30.1
0.156
14
5AOD
100
13.70
4.7
1.40
0.15
30.6
7.36
30.3
0.041
15
TIRES II
13
1.78
0.5
0.15
4.462
-------
Figure 3
Conservation Supply Curve
Auto Fuel Efficiency, Year 2010
Technology Group 1
Cost per Million BTU Saved (1988$)
o 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 7
Quadrillion BTUs of Fuel Saved
Cost—effective Cutoff is $13.20
10.00
8.00
6.00
4.00
2.00
.0.00
4 Quads
Assumes 7% Discount Rate
-------
Table 5
CONSERVATION SUPPLY CURVE. AUTO FUEL EFFICIENCY
TECHNOLOGY GROUP 2
SAVINGS IN 2010
INDIVID INDIVID NEW CAR
CONSUMER ANNUAL NEW CAR S NEW CAR FLEET NEW CAR
TECHNOLOGY COST-S COST MPG INCR MPG INCR MPG INCR FLT MPG
COST CNSRVD 2010
FUEL/ FLEET
MMBTU MPG
2010
Savings
QUA’D. BTU
BASE, 1987
21.1
0.00
21.1
0.801
1
4V
0
0.00
6.8
1.35
1.59
22.7
0.86
22.7
0.823
2
TRANS MAN
40
5.48
10
2.11
23.6
1.29
23.5
0.414
3
AERO
27
3.7.0
4.6
1.05
0.89
0.13
23.8
1.63
23.7
0.058
4
RCF
11
1.51
1.5
25.7
1.77
25.6
0.803
5
IDLE OFF
80
10.96
11.0
2.61
27.6
2.09
27.4
0.680
6
IVC
80
10.96
10.0
2.57
1.93
28.0
2.29
27.8
0.122
7
ACCESS
15
2.06
1.7
0.47
0.38
28.2
2.63
27.9
0.043
8
TCLU
35
4.80
3.0
0.84
0.13
29.1
2.71
28.8
0.277
9
ADV FRIC
40
5.48
4.0
1.13
0.90
29.3
2.99
29.1
0.086
10
11Th/TIRE
11
1.51
1.0
0.29
0.29
30.0
3.02
29.7
0.177
11
CVT
50
6.85
4.7
1.38
31.2.
3.62
30.9
0.334
12
OHC
74
10.14
6.0
1.80
1.24
.
31.9
4.76
31.6
0.181
13
FWD
150
20.55
10.0
3.12
0.72.
0.63
32.5
4.89
32.2
0.152
14
MPFI
56
7.67
3.5
34.4
6.32
33.9
0.412
15
MT RED
130
17.81
6.6
2.15
1.83
35.0
7.08
34.6
0.136
16
5A01)
100
13.70
4.7
1.62
0.65
35.2
8.46
34.7
0.036
17
TIRES II
13
1.78
0.5
0.18
0.18
-------
Figure 4
Conservation Supply
Auto Fuel Efficiency, Year
Technology Group 2
Cost per Million BTU Saved . (1988$)
Curve
2010
0 1
.2 3 4
Quadrillion BTUs of Fuel Saved
Cost—effective cutoff is $13.20
10.00
8.00
6.00
4.00
2.00
0.00
5.5 Quads
5
6
Assumes 77 Discount Rate
-------
DRAFT
associated with each technology above $10.56 are not deemed cost
effective. This level of savings represents a 22% reduction in
the fuel that would be consumed by automobiles in the year 2000,
if new car fuel economy were held to its 1987 level of 28.3 mpg
(21.7 mpg actual in 2000). Figure 1 shows that, using Technology
Group 1, the maximum cost—effective level of new car fuel economy
in 2000 is 33.4 mpg (43.6 mpg, EPA-rated). Only one technology
on the list, the advanced generation of efficient tires are more
expensive than EIA’s pcojected gasoline price in 2000, and thus
fails this test of cost effectiveness.
Figure 2 shows the results of using Technology Group 2. As
can be seen, all but the last two technologies are. cost
effective. Fuel savings of 2.5 quads (26%) are achievable using
cost—effective technologies. Again, this level of savings is
relative to how much fuel would be used if new car fuel economy
were held at 1987 levels. Using the cost-effective technologies
in Technology Group 2 to the extent used here would result in a
new car fuel economy level of 37.6 mpg (49.0 mpg EPA-rated).
Supply Curves for the Year 2010 (Figures 3 and 4)
Both technology groups are entirely cost effective in the
2,010 time frame. This result is a consequence of the most
expensive technologies (tires, weight reduction, and five—speed
21
-------
DRAFT
automatics) having a lower real cost than in the year 2000, and
of higher fuel prices. Figures 3 and 4 reveal that there is room
for. other more expensive fuel economy technologies not considered
here. Fuel, savings relative to frozen efficiency rise
substantially above the year 2000 savings. This occurs because
new, high fuel economy cars dominate the fleet in the year 2010,
whereas they didn’t in the year 2000. Cost-effective savings in
the year 2010 are 4.5 quads for Group 1 and 5.5 quads for Group
2. Cost-effective new car fuel economy levels are 43.7 MPG for
Group 1 .and-5Q:.,3 MPG Lor Group 2.
Comparison of Fuel. Saving Results to Market Scenarios
Up to this point, fuel savings, have been calculated relative
to how much fuel would be consumed in the years 2000 (or 2010) if
new car fuel economy were frozen at 1987 levels between the years
1992 and 2000 (or 2010). It is also useful to compare fuel
savings from the high levels of fue.l economy used here with
projections of market driven fuel economy improvements. Doing so
will give some indication of how much fuel could be saved over
and above a market, or no fuel economy policy scenario.
Johnson, et. al. of Argonne National. Laboratory recently
developed some projections of market driven increases in fuel
economy. 10 They estimate in their base case that average
22
-------
DRAFT
automobile fleet (all cars on the road) fuel economy will reach
27.6 MPG (EPA—rated) in 2000., and 37.4 MPG (EPA—rated) in 2010.
These estimates are based on a fuel price projection for the year
2000 that is the same as this study’s. ($1.32/gallon), and on a
projection for the year 2010 that is higher than this study’s
($1.87/gallon vs. $1.65/gallon). Given the inaccuracies involved
in any projections this far out into the future, the fuel price
difference in the year 2010 was deemed small enough not to
require adjustments to make the market fuel economy levels
projected in the Argonne study match those used in. ..tl- nalysis.
In the year 2000, fuel savings relative to the market
scenario are the same as fuel savings relative to frozen
efficiency because Argonne did not project an increase in new car•
fuel economy by 2000. In the year 2010, fuel savings relative to
the market scenario fall well below fuel savings relative to
frozen efficiency because Argonne projects a very substantial
increase in fuel economy between 2000 and 2010.
Cost—effective new car fuel economy in the year 2010 rises
only slightly above the year 2000 levels because a few additional
fuel economy measures become cost effective in the year 2010.
The results of this comparison as well as previous results are
contained in Table 6.
23
-------
Table 6
RESULTS
Fuel Savings
(Relative to:. 1987 Efficiency, Level/Market Projection)
Cost Effective New Car Fuel Economy (EPA-Rated)
Group 1
Group 2
2000
2.1/2.1 Quads
(22%/22%)
43.6 MPG
2.5/2.5’ Quads
(26%/26%)
49.0 MPG
2010
4.5/1.3 Quads
(35%/i 3%’)
43;7 MPG
5.5/2.6 Quads
(43%/25%)
50.3 MPG
-------
DRAFT
DESCRIPTION OF TECHNOLOGIES USED IN GROUPS 1 AND 2
The following section contains brief descriptions of the
technologies used in this analysis, and estimates of their
associated fuel economy improvements. The information in these
desdriptioris were derived from numerous sources. 11
Intake Valve Control
Intake valve timing and lift are optimized for a particular
engine speed in conventional engines (typcially in the high rpm
range). At other engine speeds, less than optimal valve timing
and 1 lift can substantially reduce fuel economy and power. New
valve control systems that vary timing and lift over a range of
engine speeds can largely overcome these problems. These new
systems are currently the subject of much research and
development activity. With complete control of intake valves, it
is may be possible to eliminate the throttle plate, a major cause
of energy loss at low engine speeds. Without a throttle plate,
the efficiency of a gasoline engine can approach that of a
die el. Intake valve control also offers substantial emissions
reductions.
Several manufacturers,. including Honda and Nissan, currently
offer intake valve control systems, but these systems are
25
-------
DRA T
rudimentary compared to the more advanced electric, hydraulic, or
pneumatic systems being developed by numerous manufacturers and
part suppliers. New systems are estimated to provide a 10% fuel
economy benefit.
Roller Cam Followers
The interface between a cam and flat-faced cam followers is.
the second largest source of engine friction Cthe largest source
is the piston rings) and may account for 25% of total engine
friction. Roller cam followers can reduce this friction. They
are now used in over half of new engines. They are estimated to
provide a 1.5 percent. increase in fuel economy.
Multi-point Fuel Injection
Carburetors are rapidly being replaced by fuel injection
systems. Fuel injection systems offer more control over fuel
metering, resulting in more power, better fuel economy, and lower
emissions.. One form of fuel injection, throttle body injection
(TEl), uses one or two injectors to inject fuel upstream of the
intake manifold. These systems offer abàut a 3 percent gain in
fuel economy. A more precise form of fuel injection, called
multi-point fuel injection (MPFI), injects fuel into the intake
manifold, just upstream of the intake valves. MPFI can improve
26
-------
DRAFT
fuel economy an additional 3 percent above TBI.
For this analysis, both TSI and MPFI were used to displace
carburetors. MPFI, however, was used to displace all TEl by the
year 2000.
FOUR VALVES PER CYLINDER ENGINES
Conventional spark ignition engines contain two valves per
cylinder, one intake and one exhaust. In recent years, four
valves per cylinder engines have become commonplace. Intake air
entering cylinders in four valve engines encounters less
friction, providing better volumetric efficiency. Smaller and
lighter valve train parts reduce valve train inertia, and allow
higher engine speeds. Four valve engines can typically produce
25 to 35 percent higher horsepower than their two valve
counterparts (although, this is achieved at higher rpm). Thi.S .
higt er power output allows a smaller engine to be substituted for
a larger engine.
Using a strategy of holding horsepower roughly constant, and
substituting a 4-valve 6—cylinder engine for an 8-cylinder.
engine, a 4—valve 4-cylinder engine for a 6—cylinder engine, and
a 4-valve 4-cylinder for a 4—cylinder engine, fuel economy can be
improved by. approximately 10 percent, 10 percent, and 5 percent,
27’ .
-------
DRAFT
respectively. Together, these substitutions will result in a
fuel economy improvement of about 6.8 percent, assuming that 18
percent of the substitutions are 6-cylinder for 8—cylinder, 23
percent are 4—cylinder for 6—cylinder, and 64 percent are 4—
cylinder for 4—cylinder.
AERODYNAMIC IMPROVEMENTS
Aerodynamic drag is the resistance encountered by moving a
vehicle through air, and is a function of both vehicle size and
shape. The coefficient of drag is a measure of that resistance.
The larger the coefficient, the higher the drag. The
coefficients of drag for 1987 car models vary widely, but average
abo it .40. Rounded, aerodynamic styling has become popular in
recent years. Widespread use of more advanced aerodynamic
designs could drop the coefficient to approximately .3 by the
year 2000, and improve fuel economy by about 4.6 percent.
TRANSMISSION IMPROVEMENTS
Two transmission improvements are included here, torque
converter lockup and electronic transmission control. A torque
converter in an automatic transmission transfers drive power from
the engine to transmission gears. It serves a purpose similar to
the clutch in a manual transmission. The torque converter allows
28
-------
DRAFT
“slippage” when a vehicle begins moving and when it shifts gears.
However, its also allows a small amount of slippage after
cruising speed is attained, resulting in energy loss. A torque
converter lockup prevents this unintended slippage, and yields a
fue]L economy improvement of about 3 percent.
Electronic transmission control provides more precise
control of gear shifting than conventional controls.
Transmissions controlled electronically operate in more fuel
efficient gears a larger portion of the time, resulting in about
a 1.5 percent increase in fuel economy.
When combined into the same measure in Technology Group 1,
electronic transmission control and torque converter lockup
produce a 2.2 percent increase in fuel, economy.
OVERHEAD CAM
Overhead cams have less parts and mass than their pushrod
courtterparts, and thus have lower inertia. Lower inertia reduces
the energy required for valve operation, and allows the valves to
stay open longer, improving engine breathing. Overhead cams
provide, about a 6 percent improvement in fuel economy.
29
-------
DRAFT
FRONT WHEEL DRIVE
Front wheel drive is a weight saving measure. The
driveshaft and rear axles are eliminated, and the resulting body
redesign improves the interior, space/weight ratio. Although the
fuel economy improvement that results from converting to front
wheel. drive is. large, 10 percent, the potential for improving
automobile fleet fuel economy is relatively small because most
cars, 76% in 1987, already use front wheeldrive.
CONTINUOUSLY VARIABLE TRANSMISSION
Manual and automatic transmissions use discrete gearing to
adjust the ratio of engine to axle speed. Engine speed is thus
often well above or below a speed that is sufficient for
delivering the power needed at the wheels and that maximizes fuel
ecor omy. Continuously variable transmissions (CVT), on the other
hand, have a continuum of gear ratios between a minimum and
maximum gear ratio. Better management of engine speed is thus
possible, resulting in improved fuel economy.
Several CVT designs have been researched, but the most
common type contains variable diameter pulleys connected with a
be]. . A small number of CVTs of this design have been installed
in production vehicles, including the Subaru Justy. Current
30
-------
DRAFT
materials and designs limit use of CVTs to small cars with low—
torque engines. As analyzed here, CVTs are assumed to replace
both three and four speed automatics, providing an average 4.7
percent increase in fuel economy.
IMPc{0VED ACCESSORIES
Engine accessories, such as the water pump, power steering
pump, cooling fan, and alternator, can account for a significant
fraction of fuel consumption. Improved accessories are thus an
important target for fuel economy improvements. Electric cooling
fan , which operate intermittently, reduce fuel consumption.
Redqcing heat rejection to the engine coolant can reduce the
amount of work done by the water pump. Replacing a hydraulic
power steering pump with an intermittently operated electric
motor also reduces energy consumption. Variable displacement air
conditioning compressors are also in important energy saving
innovation. Together, these measures are estimated to improve
fuel economy 1.7 percent.
ADVANCED FRICTION REDUCTION
Internal engine friction is also a significant cause of
energy consumption. The largest source of friction in the engine
is the interface between the cylinder walls and the piston/piston
31
-------
DRAFT
ring assembly. Low—tension piston rings; closer machining
tolerances for pistons, cylinders and bearing surfaces; and
improved piston designs, among other measures, can improve ‘fuel
ecor om ’ an estimated 4 percent.
FIVE-SPEED AUTOMATIC OVERDRIVE TRANSMISSION
As discussed above in the section on CVT5, automatic
transmissions use discrete gearing to adjust engine to axle speed
ratios, and because these ratios are fixed, the engine usually
operates above or below a speed that is optimal ‘for fuel economy.
Adding an extra gear reduces the ratio difference between gears,
allowing the engine to operate closer to optimal speeds.
This measure includes a transition from three, to four, to
five speed automatics. As analyzed here, the five-speed replaces
some three-speeds and some four—speeds, resulting in an average
fuel economy improvement of 4.7 percent. ‘
IMPROVED LUBRICATION AND TIRES
New lower viscosity lubricants (5W—30 for engine oil), with
friction reduction additives can reduce engine and transmission
friction. Furthermore, wider use of, high-pressure P—metric
radials would reduce rolling resistance. Together, these
32
-------
DRAFT
measures are estimated to improve fuel economy 1 percent.
WEIGHT REDUCTION
Average new passenger car weight was reduced about 900
pounds in the late 1970s. Since then average inertia weight has
remained at about 3100 pounds. (It has risen about 100 pounds
since 1987.) Despite previous deep reductions in vehicle weight,
weight can be reduced substan-tially more without reducing vehicle
size. More use of lighter weight materials, primarily high—
str ngth alloy steel and reinforced plastics, would enable
manufacturers to reduce vehicle weight by 10 percent, resulting
in a 6.6 percent increase in fuel economy.
TIRES II
Tire rolling resistance consumes about a third of the energy
deli vered to the wheels in the EPA urban driving cycle. Tires
with lower rolling resistance would, therefore, obviously improve
fuel economy. Use of new low-profile radials would improve fuel
economy about 0.5 percent.
AGGRESSIVE TRANSMISSION MANAGEMENT
This measure includes far more aggressive management of the
33
-------
DRAFT
traflsmission than assumed in Electronic Transmission Control
above. In this measure, gear shifting is controlled
electronically with the gear chosen to maximize fuel economy,
except when a driver’s, pressure on the accelerator indicates the
need for high power. This means that engine speed will be,
substantially lower than is now typical. For four cylinder
engines, it would be near 1500 rpm (instead of 2500—3000 rpm),
except when substantial power is called for.. There would be some
sliqht delay in down-shifting to gain power, and more shifting,
but advanced electronic control woui.d reduce the noticeability of
these changes to a driver. Use of aggressive transmission
management would improve fuel, economy-about 10 percent.
IDLE-OFF
In this measure, the engine is turned of f and declutched
whenever a conventional car would idle or decelerate. A second
clutch between the crankshaft and the flywheel would allow the
flywheel to continue spinning after the engine had been turned
of f. The flywheel would then be used to restart the engine.
(For long off periods, electric boosting of the flywheel, or
electric starting would be necessary.) This technology has been
fully developed by Volkswagen. It would require more braking
during deceleration —— because the engine wouldn’t be used as a
brake as it is now —— and would create a different driving feel.
34 -
-------
DRAFT
Conservatively, idle-off would improve fuel economy about 11
percent.
35
-------
DRAFT
REFERENCES AND NOTES
1. Difiglio, Carmen, K.G. Duleep, and David L. Greene, “Cost
Effectiveness of Future Fuel Economy Improvements,”
submitted to The Energy Journal , August 1988; “Developments
in the Fuel Economy of Light-Duty Highway Vehicles,”
prepared for the Office of Technology Assessment by Energy
and Environmental Analysis, Inc.(EEA), Arlington, VA, August
1988; “Analysis of the Capabilities of Domestic Auto—
Manufacturers to Improve Corporate Average Fuel Economy,”
prepared for the U.S. Department of Energy by EEA, April
1986; “Documentation of the Characteristics of Technological
Improvements Utilized in the TCSM,” prepared for Martin
Marietta Energy Systems, Inc. by EEA.
2. Difiglio, et. al., ibid.
3. Average interior volume and performance levels have
increased slightly since 1987. Therefore, this analysis
cannot be strictly interpreted as holding these measures
constant. If performance and interior volume levels were
held at their 1989 levels, a slightly lower fuel economy
level would result.
4.. A 7% discount rate was chosen to be consistent with the
discount rate being used by the U.S. Department of Energy’s
studies to support development of the National Energy
Strategy. The mileage distribution was taken from the U.S.
Department of Transportation’s 1983—1984 Personal
Transportation Study. Since cars are driven many more miles
in their first years of use than in their latter, capital
recovery for technology improvements is accelerated,
resulting in a lower annual capital charge. Using the DOT
mileage distribution results in annual capital charge equal
to 96% of what it would be were capital recovered in equal
increments over ten years.
5. Difiglio, et. al., op. cit.
6. Based on ACEEE vehicle simulation software runs.
7. Patterson, Phil, and Fred Westbrook
8. See Department of Transportation, reference 3.
9. Ross, Marc, “Energy and Transportation in the United
States,” Annual Review of Energy , 1989.
10. L. Johnson, et. al., “Energy Efficiency: How Far Can We Go?
—— Transportation,” Draft, Argonne National Laboratory,
1989.
36
-------
DRAFT
11. Information for technology descriptions were derived from:
Charles Amann, “The Automotive Engine — A Future
Perspective,” SAE Technical Paper Series, 891666,. 1989;
Deborah Lynn Bleviss, The New Oil Crisis and Fuel Economy
Technologies I Preparing the Light Transportation Industry
for the 1990s , (Westport, CT: Greenwood Press, Inc.), 1988;
Energy and Environmental Analysis, Inc., “Documentation of
the Characteristics of Technological Improvements Utilized
in the TCSM,” prepared for Martin Marietta Energy Systems,
Inc., Oak Ridge, TN, 1985; 1989 issues of Automotive News ,
Detroit, MI; 1988—1989 issues of Ward’s Engine Update ,
Detroit, MI; U.S. Department of Transportation, “Low Tension
Piston Rings and Roller CAM Followers for Engine Friction
Reduction —— Costs of Retooling and Fuel Economy Benefits,”
DOT MS 807 332, 1988; Charles Gray, Jr. and Jeffrey Alson,
“The Case for Methanol,” Scientific American , November 1989;
Ulrich Seiffert and Peter Walzer, The Future for Automotive
Technology , (London: Frances Pinter, 1984); and various
ACEEE analyses.
37
-------
Table 7
CONSERVATION SUPPLY CURVE, LIGHT TRUCK FUEL EFFICIENCY
TECHNOLOGY GROUP 1
SAVINGS IN 2000
INDIVID
INDIVID
NEW
CAR
COST CNSRVD
2000
2000
CONSUMER
ANNUAL
NEW
CAR %
NEW
CAR
FLEET
NEW CAR
FUEL/
FLEET
Savings
.
TECHNOLOGY COST-S
COST
MPG
INCR
MPG
INCR
MPG
INCR
FLT MPG
MMBTU
MPG
QUAD. BTU
BASE, 1981 ‘
16.6
16.4
1
LUBRICANTS 2
0.21
1.0
0.17
0.17
16.8
0.31
16.4
0.031
2
ACCESS 10
1.37
2.0
0.34
0.27
11.0
0.79
16.6
0.050
3
RCF 12
1.64
1.5
0.26
0.13
17.2
1.28
16.6
0.023
4
IVC 80
10.96
10.0
1.72
1.29
18.4
1.40
11.2
0.221
5
4V 88
12.06
8.4
1.55
1.02
19.5
1.94
17.7
0.159
6
AERO I 40
5.48
3.4
0.66
0.66
20.1
2.19
18.0
0.097
7
TCLU 35
4.80
3.0
0.60
0.18
20.3
2.24
18.1
0.026
8
OHC 96
13.15
6.0
1.22
0.91
21.2
3.19
18.5
0.124
9
CVT 100
13.10
6.5
1.38
0.14
21.4
3.22
18.5
0.018
tO
ADV FRIC 80
10.96
4.0
.
0.85
.
0.68
22.1
4.11
18.8
0.087
11
ETC 30
4.11
1.5
0.33
0.26
22.3
4.14
18.9
0.032
12
WT RED 138
18.91
6.6
1.47
1.10
23.4
4.60
19.4
0.129
13
MPFI 84
11.51
3.5
0.82
0.52
23.9
5.38
19.6
0.058
14
5AOD 150
20.55
6.5
1.56
0.62
24.6
5.44
19.8
0.066
15
AERO II 80
10.96
3.4
0.84
0.63
25.2
5.53
20.1
0.064
16
TIRES 20
2.74
0.5
0.13
0.13
25.3
9.37
20.1
0.013
1 • 1 98
-------
Table
CONSERVATION SUPPLY CURVE, LIGHT TRUCK FUEL EFFICIENCY
TECHNOLOGY GROUP 2
SAVINGS IN 2000
.
INDIVID
INDIVID
NEW
CAR
COST CNSRVD
CONSUMER
ANNUAL
NEW
CAR %
NEW
CAR
FLEET
NEW CAR
FUEL/
FLEET
Savings
TECHNOLOGY COST-S
COST
MPG
INCR
MPG
INCR
MPG
INCR
FLT MPG
MMBTU
MPG
QUAD. BTU.
BASE, 1987
0.17
16.6
16.4
1.1
LUBRICANTS 2
0.27
1.0
0.17
16.8
0.31
16.4
0.031
2
ACCESS 10
1.37
2.0
0.34
0.27
17.0
0.79
16.6
0.050
‘3
TRANS MAN 60
8.22
10.0
1.70
0.85
17.9
1.04
17.0
0.151
.4
RCF 12
1.64
1.5
0.27
0.13
18.0
1.34
17.0
0.023
5
IVC 80
10.96
10.0
1.80
1.35
19.4
1.47
17.7
0.215
6
4V 88
12.06
8.4
1.63
1.07
20.4
2.03
18.1
0.155
7
hERO I 40
5.48
3.4
0.70
0.70
21.1
2.30
18.4
0.094
8
TCLU 35
4.80
3.0
0.63
0.19
21.3
2.35
18.5
0.025
.9
IDLE OFF 120
16.44
11.0
2.35
1.17
22.5
2.39
19.0
0.146
10
OHC 96
13.15
6.0
1.35
1.01
23.5
3.53
19.4
0.117
11
CVT 100
13.70
10.96
6.5
1.53
0.15
23.7
3.56
19.5
0.017
12
ADV FRIC 80
4.0
0.95
0.76
24.4
4.55
19.8
0.082
13
ETC. 30
NT RED 138
4.11
1.5
0.37
0.29
24.7
4.59
19.9
0.031
-14
18.91
6.6
1.63
1.22
25.9
5.10
20.4
0.122
15
MPFI. 84
11.51
3.5
0.91
0.58
26.5
5.96
20.6
0.055
•16
5AOD 150
20.55
6.5
1.72
0.69
27.2
6.03
20.8
0.063
17
AERO II 80
10.96
3.4
0.93
0.69
27.9
6.12
21.1
0.061
18
TIRES 20
2.74
0.5
0.14
0.14
28.0
10.38
21.1
0.012
1.449
-------
Table. 9
CONSERVATION SUPPLY CURVE. LT TRUCK FUEL EFFICIENCY
TECHNOLOGY GROUP 1
SAVINGS IN 2010
INDIVID INDIVID NEW CAR
CONSUMER ANNUAL NEW CAR % NEW CAR FLEET NEW CAR
TECHNOLOGY COST-$ COST MPG INCR MPG INCR MPG INCR FLT MPG
COST CNSRVD 2000
FUEL/ FLEET
MMBTU MPG
2000
Savings
QUAD. STU
BASE, .1987
15.1
15.1
1
LUBRICANTS
2
0.27
1.0
0.15
0.15
15.3
0.28
15.2
0.079
2
ACCESS
10
1.37
2.0
0.31
0.24
15.5
0.72
15.5
0.125
3
RCF
12
1.64
1.5
0.23
0.12
15.6
1.16
15.6
0.058
4
IVC
80
10.96
10.0
1.56
1.17
16.8
1.27
16.7
0.543
5
4V
88
12.06
8.4
1.41
0.93
17.7
1.76
17.5
0.382
6
AERO I
40
5.48
3.4
0.60
0.60
18.3
1.99
18.1
0.227
7
TCLU
35
4.80
3.0
0.55
0.16
.
18.5
2.04
18.3
0.060
8
OHC
96
13.15
6.0
1.11
0.83
19.3
2.90
19.0
0.286
9
CVT
100
13.70
6.5
1.26
0.13
19.4
2.93
19.2
0.041
10
ADV FRIC
80
10.96
4.0
0.78
0.62
20.1
3.74
19.7
0.196
11
ETC
30
4.11
1.5
0.30
0.24
20.3
3.77
20.0
0.073
12
NT RED
138
18.91
6.6
1.34
1.00
21.3
4.18
20.9
0.28.6
13
MPFI
84
11.51
3.5
0.75
0.48
21.8
4.89
21.3
0.127
14
5AOD
150
20.55
6.5
1.42
0.57
22.3
4.95
21.9
0.144
15
AERO II
80
10.96
3.4
0.76
0.57
22.9
5.03
22.4
0.138
16
TIRES
20
2.74
0.5
0.11
0.11
23.0
8.52
22.5
0.027
2.791
-------
Table 10
CONSERVATION SUPPLY CURVE, LIGHT TRUCK FUEL EFFICIENCY
TECHNOLOGY GROUP 2
SAVINGS IN 2010
INDIVID
CONSUMER ANNUAL NEW CAR %
TECHNOLOGY COST-S COST MPG INCR
INDIVID
NEW CAR
MPG INCR
BASE, 1987
.
1
4V
0
0.00
8.4
1.27
2
LUBRICANTS
1
0.14
•
1.0
0.16
3
ACCESS
5
0.69
2.0
0.32
4
TRANS MAN
40
5.48
10.0
1.64
5
AERO I
20
2.74
3.4
0.58
6
RCF
12
1.64
1.5
0.27
7
IVC
80
10.96
10.0
1.79
8
IDLE OFF
•
80
10.96
11.0
2.12
9
CVT
50
6.85
6.5
1.32
10
ADV FRIC
40
5.48
4.0
0.82
11
ETC
15
2.06
1.5
0.32.
12
TCLU
35
4.80
3.0
0.64
13
AERO II
40
5.48
.3.4
0.73
14
ONC
96
13.15
6.0
1.32
15
WT RED
100
13.70
6.6
1.52
16
5AOD
100
13.70
6.5
1.57
17
MPFI
70
9.59
3.5
0.87,
18
TIRES
10
1.37
0.5
0.13
NEW CAR
FLEET
MPG INCR
0.84
0.16
0.26
0.82
0.58
0.13
1 .34
1.06
0.13
0.65
0.25
0.19
0.55
0.99
1.14
0.63
0.56
0.13
NEW CAR
FLT MPG
15.1
15.9
16.1
16.4
17.2
17.8
17.9
19.2
20.3
20.4
21.1
21 • 3
21.5
22.1
23.1
24.2
24.8
25.4
25.5
COST CNSRVD
FUEL/
MMBTU
0.00
0.15
0.38
0e67
0.97
1.33
1 .46
1 • 44
1 • 54
1.96
1.98
2.37
2.42
3.46
3 • 44
3.67
4.75
4.72
2000
FLEET
MPG
15.1
15.9
16.0
16.3
17.0
17.6
17.7
19.0
19.9
20.1
20.7
20.9
21,1
21.6
22.5
23.6
2402
2407
24.8
2000
savings
QUKD. BTU
0.422
0.075
0.119
0.355
0.234
0.051
0.477
0.333
0.039
0.187
0.069
0.052
0.143
0.241
0.254
0.130
00110
0.024
30315
-------
OFFICE OF HIGHWAY
INFORMNI ION IU*NAO€MENI
• ANNUAL VEHICLE-MILES OF TRAVEL AND RELATED DATA - 1988’
NY HIGHWAY CATEGORY AND VEHICLE TYPE
TABLE YR-I
OCTOBER I9B9
YEAR
1111*
•
PASSENGER VEHICLES
TRUCKS
ALL
MOTOR
VEHICLES
PERSONAL PASSENGER VEHICLES
!
•
BUSES
ALL
PASSENGER
VEHICLES
SINGLE-UNIT
tOf u-
NATION
ALL
TRUCKS
PASSENGER
CARS
2/
MOTOR-
CYCLES
2/
ALL
PERSONAL
PASSENGER
VEHICLES
2-AXLE
4-TIRE
OTHER
ALL
5INOLE-
UNIT
$900
1987
1988
*987
$906
1907
ROTOR-VEHICLE TRAVEL 0
INTERSTATE RURAL
OTHER ARTERIAL RURAL
OTHER RURAL
—
—
—
-
-
—
•
-
-
-
-
-
1 16.011
*00.667
201.932
197.610
200.065
114.502
609
492
192
$69
1.700
1.651
111.60$
109.359
205.124
195.479
207.168
I9r .239
3 1.066
20.504
76.693
73.062
94.619
90.6*8
5.472
6.267
10.840
10.305
11.944
11.66$
36.120
33.141
08.273
$4117
*06.529
102.307
20.109
27.293
*1.939
11.343
9.948
1.342
14.696
61. 134
106.212
103.610
116.469
1*1.729
101.204
*70.493
312.038
301.909
324.237
307.960
1900
$967
ALL RURAL
-
-
-
—
527.079
501.059
3.101
3.0*6
630.150
604.077
201 .267
*93.264
20.066
17.131
229.323
220.396
56.064
65.976
267.371
276.313
0 17.567
700.450
*900
1907
*900
1967
INTERSTATE URBAN
OTHER URBAN
-
—
-
-
-
—
-
-
191.912
113.662
7 )0.291
160.216
166
463
1.196
1.147
*96.100
164.0*5
710.196
662.062
40.614
40.396
197.611
161.761
1.666
5.669
17.309
*6.737
46.611
16.067
214.620
196.624
*5.743
11.764
16.351
16.332
62.264
60.021
231.17*
213.666
255.662
244.636
949.367
095.910
1900
1967
ALL UROAN 3/
-
-
—
-
111.240
063.777
1.361
2.300
0*4.604
066.077
230.168
222.105
23.171
22.406
281.331
244.691
32.091
30.066
293.425
274.677
1.206.029
1.140.764
1908
1967
TOTAL RURAL AND URBAN
1.429.297
1.356.330
10.022
9.606
1.439.319
1.364.636
5.466
5.3*0
1.444.704
1.370.161
439.123
4*6.449
II .23*
49.637
490.654
464.905
90.149
08.064
600.602
661.050
2.026.568
1.921.201
*906
1967
1900
1967
1966
1967
*908
*907
*986
*967
NUMBER OF ROTOR VEHICLES
REGISTERED I
AVERAGE RILES TRAVELED
PEA VEHICLE
FUEL CONSUMED
ITHOUSAND GALLONS)
AVERAGE FUEL CONSUMPTION PU
VEHICLE IORLLONSI
AVERAGE MILES TRAVELED PER
GALLON OF FUEL CONSUMED
141.261.696 4.684.201
*37.200.090 4.911.131
10.119 2.106
9.876 1.933
71.654.199 200.410
70.672.830 190.120
607 44
614 39
*9.95 50.00
19.20 60.00
*16.035.919
112.126.221
1.089
9.603
71.664.639
10.762.750
493
490
20.03
19.29
016.669
002.055
0.677
6.033
920.066
902.006
1.191
1.600
6.94
5.69
116.461.641
142.727.276
0.066
9.600
72.714.696
71.665.644
497
502
19.05
19.12
37.095.000
35.011.360
11.646
11.691
32.760.043
32.265.567
003
900
13.41
12.66
3.967.319 41.053.127 1.470.241
3.063.694 39.126.054 1.111.400
*2.916 11.952 01.056
*2.155 11.705 60.634
7.260.176 40.010.219 17.100.966
1.090.683 39.366.240 *6.193.469
1.832 $71 11.614
1.626 I I I 11.620
7.07 I llS 6.27
6.99 11.11 5.22
2.629.300
1.114.154
*3.850
*3.393
7.111.106
6.649.709
1.319
1.357
10.17
9.61
100.901.016
163.671.730
*0.7*6
*0.419
*29.065.000
127.515.363
607
694
*6.00
16.01
j/ THE 60 STATES AND THE DISTRICT OF COLUMBIA REPORT TRAVEL BY OF 5.000 OR OREAJER POPULATION.
HIOHNAY CATEGORY. NUMBER OF MOTOR VEHICLES REGISTERED. AND TOTAL FUEL 4/ STRATIFICATION OF THE TRUCK FIGURES IS MADE BY FHWA BASED ON THE
CONSUMED. THE TRAVEL AND FUEL ORTA BY VEHICLE TYPE AND STRATIFICATION OF *962 CENSUS OF TRANSPORTATION TRUCK INVENTORY AND USE SURVEY ITIUSI. THE
TRUCKS. AS WELL AS RELATED OATA ARE CALCULATED OY THE FEDERAL HIGHWAY COMBINATIONS REPRESENT APPROXIMATELY THE NUMBER OF TRUCK-TRACTORS WITH
ADMINISTRATION IFHWAI. ENTRIES FOR *901 HAVE BEEN REVISED BASED ON THE SEMI-TRAILIRISI AND A MAJORITY OF THE HEAVY SINGLE-UNIT TRUCKS USED
AVAILABILITY OF MORE CURRENT DATA. REOULARLY IN COMBINATION WITH FULL TRAILERISI. ALL THESE TRUCK VEHICLE
2/ SEPARATE ESTIMATES OF PASSENOER CAR AND MOTORCYCLE TRAVEL ARE NOT FIGURES MAY BE REOAROEO AS PRELIMINARY AND MAY BE REVISED PENDING FURTHER
AVAILABLE BY HIGHWAY CATEGORY. ANALYSIS OF THE TIUS DATA.
3/ •URBAN CONSISTS OF TRAVEL ON ALL ROADS AND STREETS IN URBAN PLACES
-------
A TTACHMENT C
ICF Analysis of Vehick Savings
Issues
06W0658C
-------
VEHICLE ENERGY CONSERVATION
ACEEE (Marc Ledbetter and Marc Ross) has provided ICF with passenger car
(LDV) and light duty truck (LDT) cost and fuel efficiency estimates relative to 1987 (See
Attachment B). For the purposes of this study, light duty trucks are defined as trucks
weighing less than 10,000 pounds (gross vehicle weight). Most of the ACEEE estimates
of WV and LDT efficiency improvements and costs are borrowed and adjusted estimates
from EEA.
ACEEE provided a list of 17 conservation technologies for WV (18 for LDT),
excluding the two-stroke engine. ACEEE also provided fuel efficiency contribution, cost,
and new vehicle market penetration assumptions for each of the technologies.
There are two items to note about ACEEE’s estimates. First, ACEEE did not
provide a market baseline from which to measure any improvements. Without a baseline
it is difficult to evaluate what is incremental and what likely will happen anyway. Second,
ACEEE only examined two fuel eáonomy technologies other than those already developed
by EEA (idle-off and.transmission management). EEA’s analysis focuses only on currently
commercially available, or soon to be available, technologies. Therefore, alternative
technologies, such as the two-stroke engine (one of the hottest near-term conservation
options), are not included in their analysis.
In order to supplement ACPPPI’s work, ICF has taken the following actions:
• Obtained EIA/AEO and EPA energy-use baselines.
• Provided Marc Ross with a small subcontract to estimate
energy savings from the two-stroke engine and other “exotic”
technologies.
Baseline
Table 1 and Figures 1 and 2 compare ACEEE, EEA, and EIA new light duty fleet
MPG forecasts. The EIA and EEA baselines are somewhat similar, with EEA projecting
a higher average new car MPG of about 2 MPG for LDV and LDT by year 2000. After
reviewing both EEA and EIA baselines, ICF selected the new light duty fuel efficiency
baseline from the EIA 1990 Annual Energy Outlook. The 1990 EIA/AEO baseline was
the most current forecast available to ICF. Since ACEEE did not provide any estimates
of the expected adoption of each individual technology in the baseline, ICF estimated the
proportion of total savings available from all technologies required in the baseline to yield
the total assumed baseline efficiency improvement. ICF then assumed the rest of the
reductions would be available at the unit cost estimated by ACEEE for the cost reduction
step. ICF did not make any attempt to estimate which of the identified technologies
would be the ones more widely adopted in the baseline.
Page 1 ICF Resources Incorporated
-------
2.’ Issues Raised During Analysis
EEA
ACEEE’s estimates of ‘the new MPG in year 2OOO for LDV and LDT are very
different than EEA’s “high” estimates despite the fact that ACEEE uses EEA data.
There appear to be two reasons for this difference:
ACEEE has included two additional technologies not included
in the EPA analysis (idle-off and “aggressive” transmission
management). Two additional technologies account for 76
percent of the difference between ACEEE and EEA estimates
of new WV MPG (55 percent for LDT). See Figure 1.
• ACEEE treats each of the conservation technologies to be
independent of each other. The percentage improvement in
efficiency for each option is treated as an additive improve-
ment while EEA, assuming some interaction between the
technologies, treats each as a multiplicative improvement. We
have talked with Marc Ross about the different methodology -
- he believes that the EEA approach is incorrect and is
comfortable with the independence/additive assumption which
give higher reductions. ACEEE’s assumption of technology
independence accounts for about 34 percent of the MPG
difference for LDV and 45 percent for LDT . See Figure 2.
‘Both the EEA and ACEEE estimates are supportable; the ACEEE estimates
respond to EPA’s initial request that they be aggressive in finding conservation options.1
Idle-off and transmission management may, however, involve some performance decre-
ment.
Other Technologies
A variety of new technologies at various stages of development have been identified
that appear to show promise of achieving large efficiency gains. ICF has afready included
the two-stroke engine in the analysis. Other engine’ design said to hold considerable
promise include direct-injection diesel. Some of the potential fuel efficiency technologies
(as cited by the Office of Technology Assessment, M. Ross, and D. Bleviss) are:
• Variable Geometry Turbochargers.
• Improved Electronic Controls.
Condenser Engine Cooling.
• Advanced Lubricants (Solid and Gaseous).
Pog 2 ICF Resources Incorporated
-------
• Oxygen Enrichment of Air Intake (Membrane Technology).
• Engine Stop-Start and Energy Storage (Hybrid Engines).
Page 3 ICF Resources Incorporated
-------
Table 1
Evaluation of ACEEE’s Calculation Method
Year 2000
BASE CASE OPTIMISTIC CASE
1. New Cars
1987 Base 28.20
EIA 1/ 32.69
EEA 2/ 34.39 39.89
ACEEE 3/ 42.78
ACEEE 4/ 48.31
2. New Trucks
1987 Base 20.40
ETA 1/ 22.37
EEA 2/ 24.53 26.35
ACEEE 3/ 28.76
ACEEE 4/ 31.70
Notes: 1/ EIA’s Annual Energy Outlook, Januazy 1990.
2/ EEA, October 1989. Size and performance held constant.
No on-road degradation assumed.
3/ ACEEE, December 1989. Increase in MPG due to adding
rather than multiplying fuel efficiency gains (independence assumption).
Size and performance held constant. No on-road degradation assumed.
4/ ACEEE, December 1989. Effects of aggressive transmission m n gement
idle-off, and newth thodolO Jnc1uded are included.
Size and performance held co iint. No on-road degradation assumed.
-------
FIgure 1
LDV NEW FLEET MPG
1. Using additiv. msthod end
transmission menagsmint/idu. oft.
2. UsIng additlvs method.
z
0
- I
-J
4
0
UI
a-
UI
-J
50
40
30
20
10
0
ACEEE
EEAHIgh
EEABass
E IA
1987
1967
1989 1991 1993 1996 1997 1999 2001
YEAR
-------
Figure 2
LDT NEW FLEET MPG
z
0
-a
-a
4
U i
A.
1 )
w
-a
30
20
10
0
ACEEE
EEAHI9h
EEAB s.
EIA
1987
1987’ 1989
I 991
1993
1996 1997 1999 2001
YEAR
-------
ATTACHMENT D
Memo from Michael Kavanaugh
on UDF Aircraft Engine
06W0658C
-------
March 6, 1990
To: Paul Schwengels, Barry Solomon, Ted Breton, John Blaney
From: M. Kavanaugh
Subject: Fuel economies available from ultrahigh bypass (UHB) jet
engines
Ultrahigh bypass (t3HB) engines offer fuel economies of 10-40%
over conventional engines but carry a $1 million price premium.
During the l980s, each major engine manufacturer either on its own
or in partnership began development or production of a UHB; and
each major airframe manufacturer planned to make a UHB aircraft.
By late 1989 it was clear that the potential customers (the air
carriers) were unwilling to pay the premium for increased fuel
efficiency. The engine manufacturers discontinued development and
testing and the airframe makers either cancelled development of
the airframe or altered it to accept different engines.
This memorandum reviews the efforts of the major engine and
airframe manufacturers and estimates:
* a 16.8% weighted—average, per engine, fuel-efficiency
increase for tfliBs over their next best competitor;
* a 10% potential fuel share for UHBs in 2000; 24% fuel share
in 2010;
* a 2—4% potential saving in fleet fuel use from UHB jets;
* UHB market penetration by 2000 of 1700 engines, by 2010
of additional 3300 engines for a total of 5000 engines;
* UHB premiums of $1 million per engine or $1.7 billion by
2000 and $5 billion by 2010; and,
* rates of return of 8—13% if jet fuel costs $.60 gallon and
14—21% if jet fuel costs $1.00 gallon.
Page 1
March 6, 1990
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1. UHB jets
A UBB jet is an airframe with UMB engines. “By—pass” refers
to the air passed around the combustion chamber to produce
additional thrust. Early jet engines had by—pass ratios of 1:1
meaning that as much air went through the combustion chamber as
went around it, existing conventional engines have ratios of 6:1;
GE’S latest large conventional engine (GE9O) has a by—pass of 10;
UBBS have ratios of 20-40. UMB engines vary in size from 17,000
to 30,000 lbs of thrust per hour making them ideal for short to
medium haul, narrow—body aircraft such as 727s, 737, DC9s, MD9O5
and A320s. Airbus is the exception and considered putting four
tJHBs on its wide-body, long range A340.
The design that made it to production is GE’s unducted fan
(TJDF), an aft—mounted engine with blades on the rear of the engine
that spin in the open air to provide additional thrust. It has a
by-pass of 36. Its intended use was on Douglas Aircraft’s MD-90
and Boeing’s 7J7 airframe. Other designs of UHB engines intended
for wing—mounting (e.g., for 7375, A320s, A340s) exist.
1.1 Engines
All research is completed on General Electric’s entry into
the UHB competition, the unducted fan (UDF). The UDF began in
1983 as a research project with some public funding under the
Energy Efficient Engine (E3) program. It was flight tested in
mid—1987 on 727s and MD8O5 and shopped to potential MD9O customers
by Douglas Aircraft in 1989. There were no sales. The price of a
UDF engine is $5 million which is about $1 million more than a•
state—of—the—art conventional engine of similar (25,000 lb/hr)
thrust (e.g., CFM56). The UDF is aft-mounted but in the late
1980s there were designs for wing mounting.
Pratt & Whitney teamed with Allison in early 1987 to enter
the URD competition with a 578—DX demonstrator engine. The engine
is smaller than the UDF (17,000 lbs thrust). Flight testing began
in April 1989. All the research on this engine is complete but
further work is suspended until a market for UHB5 appears.
Page 2
March 6, 1990
-------
International Aero Engines began working on UHB5 in mid-1986
with the wing—mounted Superf an. In January 1987, Lufthansa (a
German air carrier) announced its intention to use four 30,000 lb.
thrust Superfans on A340s. Development problems caused the
Superfan program to be cancelled by mid-1987.
Rolls-Royce began developing .a UHB engine (the RB509.ll) in
1986. Uncertainty over future fuel costs and uncertainty over air
carrier demand for small versus large aircraft caused Rolls—Royce
to emphasize other engines.
CFM, the GE-Snecina partnership, did not produce a UHB.
1.2 Airframes
Boeing’s entry to the tfl!B competition was the 7J7, a 150
passenger, two—aisle airframe. Originally designed with aft-
mounted engines a version with wing—mounted engines was considered
after IAE announced its intention to build the Superfan. In
August 1987, amid uncertainty over aircraft size, the ability of
UHBs to power stretched 7J7s and pricing, Boeing delayed the
7J7 program for 18 months and then cancelled it.
Douglas Aircraft’s MD9O series was the airframe most likely
to succeed in the UHB competition. The MD9O series seats from 115
to 165 passengers in single aisle configuration. It is a
derivative of the MD8O, the airframe used to flight test GE’s and
PW-Allsion’s UHBs. After more than a year of trying to market the
MD9O with UHB engines, conventional engines were offered. Within
6 weeks of formally offering the same plane with conventional
engines (IAE’s V—2500), Douglas received a firm order for 50
planes.
Airbus, whose airframes use wing—mounted engines, planned to
use the IAE Superf an. After that engine was cancelled, Airbus
modifed the wings on the A340 to accept conventional engines and
left the UHB competition.
Page3
March 6, 1990
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2. Estimated fuel savings
Fuel savings are estimated by multiplying the percentage
increase in UHB engine fuel efficiency by the share of fleet fuel
use potentially consumed by UHB engines.
2.1. Increase in engine performance
The estimates are based on the performance of GE’S UDF
because production models of this engine and performance
data are available. Arguably, the other contenders in the UHB
competition would offer similar efficiencies.
Table 1: Fuel efficiency of conventional v. UDF engine
Engine SFC % change to UDF
.484 —
V2500 .575 15
CFM56—3 .665 27
CFM56—5 .545 10
JT8D—9 or 17 .811 40
JT8D-200 .737 34
SFC - specific fuel consumption at cruise altitude is the pounds of
fuel necessary to produce a pound of thrust per hour at cruise. A
UDF requires 48 pounds of fuel to produce 100 pounds of thrust per
hour while a JT8D-200 requires 73 pounds. Supersonic engines
have SFC5 that exceed 1 and are the least efficient jet engines.
2.2 Share of fleet fuel use
UHB engines are ideal for twin—engine, short to medium haul
jets carrying up to 150 passengers such as the 737, DC9, MD8O,
MD9O, and A320. (Airbus considered using the UHB on the A340, a
long range, high capacity jet that competes with MDhls.) Twin—
engine, short to medium haul jets make up 48% of the commercial
fleet in 1990 (1938/4055) and are forecast to account for 64% of
the fleet in 2010 (37 00/5825) (Data shown in Table 2). These jets
are used (primarily) to feed hubs. The increase in plane shares
Page 4
March 6, 1990
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Table 2: PrincIpal Jets In USA Comnerical Fleet a, b, c, d, a
Fuel shares Aircraft
1980 1990 2000 2010 1980 1990 2000 2010
14 28 32 36 615 1938 2191 3700
37 21 7 1 10291183 SM 200
I
9 20 2? 12 204 615 900
15 15 15 16 227 300 405 400
15 7 3 1 380 253 117 25
18 17 23 19 131 177 343 600
‘100 100
a. Jane’s All the Worlds A$rcraft, 1985-86
b. Chit Ian Aircraft of the World
c. Encyclopedia of the WorLd’s Comerciel and Private Aircraft
d. turbine-engined Fleets of the World’s Airlines, Air World Survey, 1987
e. FAA Aviation Forecasts, March 1990
100 100 2394 4055 4835 5825
Airframe
Manufacturer Representative
Body Engines
UNB
Engine
Style I
feasible
* • new
.
N • narrow
Ii s wide
737
Boeing
JT8D-91?; CHI-56-5
N
2
x
757
Boeing
P 1J203?
N
2
0C9
Douglas
JT8D11
N
2
x
M080
Douglas
J180-200
N
2
*
C90
Douglas
V2 500
N
2
x
A-320
Airbus
CFK-56-5, V-2500
N
2
*
727
BoeIng
JT 8D-17
N
3
767
Boeing
CF6-50; CF6-80C2
we
2
A-300/310
Airbus
JT9 O-?R
we
2
A-330
Airbus
C16-80C2
we
2
DCIO
Douglas
CF6-60
U
3
LiOll
Lockheed
IB.211
U
3
MD1I
Douglas
CF6-BOC
we
3
707
HoeIng
JT3D-7
N
4
DC-a
Douglas
JT3D
N
4
747
BoeIng
Jt90-TF; CF6 -80C2
U
4
A-340
Airbus
CFN-56-5, V-2500
W
4
x
-------
reflect the replacement of three-engine 727s with new narrow—body
twins and segment growth. There is, of course, uncertainty about
this forecast which reflects the March 1990 FAA forecast.
Limitations of airport and airway space could bring about the use
of larger jets (175—225 passengers) to feed hubs, but this implies
less frequent service to hubs or lower load factors. Retirements
could proceed slower than expected. An aging fleet has higher
maintenance, crew and fuel costs but high interest rates increase
the cost of buying new jets and flat fuel prices erode (some of)
the fuel savings of new jets.
The commercial fleet is made up of jets of widely varying
size with engines that burn different amount of fuel per hour.
Short to medium haul, jets have smaller engines and burn
proportionally less fuel, than long haul jets. Accordingly fuel.
shares for twin-engine jets differ from the share represented by
the number of twin-engine jets in the fleet. The results (Table
2) of a fuel share calculation based on engine hours and relative
fuel flows show twin—engine jets consume 32% of fleet fuel use in
2000 and 36% in 2010.
The twin—engine, short to medium haul segment of the
commercial fleet is undergoing three types of changes:
* expansion, forecasts call for 1760 jets from 1990 to 2010,
(850 jets or 1700 engines between 1990 and 2000, 910 jets
or 1810 engines between 2000 and 2010);
* renewal, there is no consensus estimate but a conservative
one is that 1200 jets will be needed as new jets rep-lace
old; and
* up—dating after 2000 as middle—aged 737s and MD8Os are re—
• engined (about 725 jets will be candidates)
In all, the engine market for this segment exceeds 7000
engines. Given appropriate incentives, wing-mounted UHBs could
be brought to production and together with the completed and ready
to be installed aft-mounted TJHBs could meet most if not all of the
engine demand from this segment. A conservative estimate of 5000
engines is shown in Table 3.
Page 5
March 6, 1990
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Table 3: tJNB engine demand by commercial jets to 2010
Year
Engines—new
Engines—replacement
Total
2000
1700
0
1700
2010
1750
.
1550
3300
Total
3450
1550
5000
Within a given class (e.g., twin-engine, narrow—body), engine
sizes are similar and plane shares are a good indicator of fuel
shares for subdivisions of that class. The modèrnization scenarjo
of 850 UHB jets by 2000 implies that UHBs will, make up 30% of the
jets in the twin-engine, narrow body class and will have a fleet
fuel share of about 10% (30% of 32%) ;’ -By--20’10 an additional 1650
UHB jets will enter the fleet making 2500 UBB jets (the 850 from
2000 plus 1650 new or reengined jets) in the fleet by 2010. These
UHB jets will represent about 67% of the twin—engine, narrow body
segment and will have a UHE fuel share in 2010 of 24% (67% of
36%).
2.3 Estimate of fuel savings
Expanding and modernizing the short to medium range segment
of the commercial jet fleet with UHBS instead of ‘conventional
engines could reduce’ jet fuel use 2% in 2000 and 4% in 2010.
Page 6
March 6, 1990
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Table 4: Fuel savings of conventional v. UDF engine
Engine % change still weights weighted
over UDF produced change
V2500 15 x .4 6.0
CFM56—3 27
C7M56—5 10 x .4 4.0
JT8D—9 or 17 40
JTBD—200 34 x .2 6.8
Average 16.8
Fuel share
10% in 2000 1.7%
24% in 2010 4.0%
Engines that compete with TJBBe in the new and replacement
markets are the V2500, CFN56—5 and JT8D—200 series. Table 4 shows
UHBs have a 10 to 34% advantage in fuel efficiency over these
engines. Table 4 shows UHBs have a 27 to 40% advantage over the
CFN56—3 and JT8D—9s/l7s, but these engines, although still in use,
are no longer produced and are not considered competitors with
tJHBs. Accordingly, fuel efficiency improvements are calculated
relative to a weighted average of the new conventional engines.
The weights in Table 4 indicate UHBs are more likely to compete
with the best of the new engines. Arguably, the UMB engines made,
in 2010 will outperform those made in 2000 and fuel savings might
appear to be larger than those estimated in Table 4. By the same
logic, however, conventional engines will also have improved over
the period 2000—2010 so that in percentage comparison between
conventional engines and tJHBs remains constant.
Estimates of fuel savings depend on forecasts of jet fuel
use. DOE’s forecast applies to all jets while FAA’s focuses on
commercial aviation. Both are based on judgment rather than
forecasts of underlying factors such as economic growth, fleet
composition and modernization. The fuel forecasts, then, provide
Page 7
March 6, 1990
-------
an inexact reference for measuring increases in fuel efficiency.
This analysis does not modify the judgments of the forecasters
except that whenever modernization occurs tIHB engines are used and
fleet fuel use is reduced 2-4% per year.
The improvement in fuel use applies to the commercial jet
fleet. It consumes 65% of jet fuel (military jets consume 25%;
business jets 10%). To calculate fuel savings using the DOE jet
fuel forecast of 1.73 million/bb]./day in 2000, the commercial
share (65%) is multiplied by the UHB savings (2%) to arrive at
savings of 22,500 bbl/day in 2000 and 51,220 bbl/day in 2010
(.04*.65*1.97E06 bbl/day).
3. Economics
UBB/VDF engines are priced at $5 million, a $1 million
premium over the next best engine the CFM56—5 or IAE V2500. Given
the modernization scenario, $1.7 billion in premiums are paid by
2000 and an additional $3.3 billion during the period 2000-2010.
There is simply rio evidence about maintenance costs for tJHBs, and
they could be above, the same or below that of conventional
engines. This analysis assumes no incremental 0&M costs.
The premiums have opportunity costs, they could be invested
and earn a return reflecting the risk of the investment. Low risk
investments such as U.S. Treasury securities return 8.5%; the
average risk premium is about 7%, implying a 15.5% return for
investments of average risk. The savings from a more fuel
efficient engine, an investment of some risk must make a
comparable return.
Fuel savings depend on fuel prices and hours of use. The
average 2—engine, narrow—body jet flies 3200 hours a year (60
hrs/vk) and consumes around 890 gallons per hour or 2.8 million
gals per year (1.4 million gallons per engine). For $2. million a
carrier can purchase a UDF and realize a 10% increase in fuel
efficiency over a CFM56—5 or 15% over a IAE V2500. This will, save
between 140,000 and 210,000 gallons per year. At $2. gallon this
is a $140,000 to $210,000 return on a $1 million investment or 14%
to 21%. Returns of this magnitude might be enough for air
carriers. At $.60 gallon the saving are $84,000 to $126,000 or
8.4% to 12.6*; these returns are inadequate.
Page 8
March 6, 1990
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ATTACHMENT E
LBL Report on Residential and
Commercial Conservation
06W0658C
-------
SUPPLY CURVES OF CONSERVED ENERGY:
RESIDENTIAL AND COMMERCIAL SECTORS
• James E. McMahon
Lawrence Berkeley Laboratory
March 2, 1990
OUTLINE
0. Introduction
1. Principles of Supply Curves of Conserved Energy
2. Methodology
2.1 Residential Sector
2.2 Commercial Sector
2.3 Administrative Costs
3. Technology Data Base
4. Current Market
5. Projections
6. Results: Costs of Conserved Energy
DRAFT
-------
-2-
0. INTRODUCTION
Section 1 describes supply curves of conserved energy.
Section 2 describes the methodology used in this study to estimate costs of
conserved energy for the residential and commercial sectors, including a brief
discussion of the administrative costs which are added to the technology costs.
Section 3 describes the technology data base.
Section 4 discusses the current market, including a list of appliances
currently bearing energy efficiency labels. Market barriers to adoption of energy
efficient technologies are listed.
Section 5 describes the base case projections, from which additional conser-
vation costs and savings are calculated.
Section 6 presents the results, namely costs of conserved energy and
energy savings for the years 2000 and 2010 for the residential and commercial
sectors,
DRAFT
-------
-3-
1. PRINCIPLES OF SUPPLY CURVES OF CONSERVED ENERGY
The supply curve of conserved energy is a useful tool in least-cost utility
planning. It graphically portrays the technical potential for energy conservation in
a way that is easy to grasp and assess. (See Figure 1.) Just as important, how-
ever, is the consistent accounting frameworkunderlying the supply curve. The
consistency of assumptions regarding costs, energy savings, lifetimes, and other
key factors simplifies the comparison of individual conservation measures. More
generally, the methodology permits comparison with new energy supplies. A
table - often a spreadsheet - provides the back-up information for the supply
curve. The assumptions behind the supply curve of conserved energy are
presented below. Many of the complications of the approach are not described in
order to present the overall approach; more detailed discussions are listed in the
Bibliography. The same approach can be used with only minor modification for
assessing measures to reduce water, C02, and other resources.
The Cost of Conserved Energy
The Cost of Conserved Energy (or CCE) is the measure of economic value
of a conservation measure in a supply curve of conserved energy and. it
represents the vertical axis of the conservation supply curve. The CCE is an
investment statistic. The CCE is similar to Return on Investment, Payback Time,
and Internal Rate of Return except that it relies on slightly different information.
The Cost of Conserved Energy is defined by the formula:
Investment d
— Energy Savings 1.—(1 + d)”
The formula consists of two parts. The first part is simply the ratio of the conser-
vation measure’s cost over, the savings (usually expressed per year). The second
part is an annuity factor. This factor converts the measure’s cost into an annual
payment, based on the lifetime, n, and discount rate, d. The dimensions of the
CCE depend on the units used in the CCE calculation. For example, if the cost is
expressed in dollars, the energy savings in kilowatt-hours per year, the interest
rate per year, and the lifetime in years, then the resulting CCE will have the
dimensions of $JkWh. The intuitive meaning of the CCE is the cost to save a unit
of energy. The cost of conserving other resources can also be calculated by sub-
stituting that resource, such as tons of avoided C02 or gallons of saved water, in
DRAFT
-------
-4-
place of electricity savings.
For each measure in the supply curve, one must specify the cost, energy
savings, and lifetime. (The discount rate is assumed to be the same for all meas-
ures.) This requirement already imposes a degree of consistency among conser-
vation measures and permits one to compare CCEs of measures. The most
attractive measures are those with lower CCEs. Ranking measures by increas-
ing CCE establishes an order of economic attractiveness, the most attractive first.
This procedure establishes the sequence of conservation measures on the sup-
ply curve.
The CCE alone gives no information about cost-effectiveness. To decide if a
conservation measure is cost-effective, the CCE must be compared to the price
of the energy that is avoided. Note that the CCE and energy price will have the
same dimensions (if the inputs are correctly chosen). If the cost of conserving a
unit of energy is less than that of the displaced energy, then a measure is cost-
effective. For example, a refrigerator efficiency improvement might have a CCE
of $0.02/kWh. (The cost of the measure was dollars and the energy savings in
kWh, hence the CCE is $ikWh.) To decide if this measure is cost effective, com-
pare it to the price of electricity the avoided electricity use, say, $0.10/kWh. On a
supply curve of conserved energy, an “energy price line” can be drawn across
until it intersects with measures having CCEs higher than the price (see Figure
1). All measures below the energy price line are cost-effective; those above the
line are not.
Micro and Macro Supply Cur’es
The simplest supply curve of conserved energy consists of a collection of
unrelated conservation measures. In this case, the measures can be stacked, in
order of increasing CCE, on the supply curve. Each measure is represented by a
step whose width is the energy saved (per year) and whose height is the CCE.
This is sometimes called a “micro” supply curve of conserved energy because
each step represents savings from one application of that measure, that is, one
furnace, one car, or one light bulb. In contrast, a step in a “macro” supply curve
may represent the average savings and CCE for the measure in thousands of dif-
ferent furnaces, cars, or light bulbs.
Most micro supply curves are more complicated than the one first described
because the measures are connected. For example, a typical supply curve might
represent the conservation measures that could be applied to a residential water
DRAFT
-------
-5-
heating system. In this case, the energy savings are no longer independent
because the savings from one measure will often depend on the measures that
have already been implemented. The energy savings attributed to an improve-
ment in the water heater’s efficiency will depend on the amount of hot water
demanded which, in turn, will depend on the measures that have already been
implemented (such as a low-flow showerhead). Put another way, the sum of sav-
ings of each measure implemented alone will be greater than the two imple-
mented together. If the interdependence of the measures is not taken into
account, then it is possible to “double-count” the energy savings. Under extreme
circumstance, it is possible to demonstrate that more energy can be saved than
was actually used in the first place (an embarrassing result). Sometimes the
interdependence of measures can save more energy than the measures applied
singly. Improving the efficiency of lighting in commercial buildings, for example,
may save lighting and air conditioning energy.
A properly-constructed supply curve of conserved energy will avoid double-
counting errors by the following procedure. The CCE is calculated for all of the
measures. The cheapest (i.e., lowest CCE) measure is selected and “imple-
mented”, that is, the energy savings from the first measure are subtracted from
the initial energy use. The new energy use is used to recalculate the CCEs of the
remaining measures. (In general, the CCEs will rise.) The measure with the
lowest CCE is selected, and implemented. The energy use is recalculated, along
with the CCEs for this lower energy use. The procedure is repeated until all the
measures have been ranked. This procedure has several implications about
energy savings of measures when taken out of order this is discussed in Meier
(1982).
A key assumption in the supply curve of conserved energy is the initial
energy use (or baseline). Since the supply curve shows reductions in energy use
from the baseline, it is crucial to carefully define the baseline. It is very difticult to
save energy that was not used in the first place. Determining the initial energy
use, and the energy-related characteristics is often the most difficult part of con-
structing a conservation supply curve. Measured data is obviously superior but
more expensive to obtain.
Macro Supply Cur ies
A “macro” supply curve of conserved energy refers to a combination of micro
supply curves. Thus, one might construct a macro supply curve for all the
DRAFT
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-6-
residential electric water heaters in Massachusetts or central air conditioners
(actually the end use) in Texas. It is impossible to evaluate and aggregate the
savings from every unit in a large collection. Instead, prototypes are created that
represent the average micro situation. Then, with the assistance of engineenng
calculations, simulations, or even measured data, average savings are estimated
for a collection of conservation measures. Those savings for an individual unit
are then multiplied by the number of units (i.e., water heaters in Massachusetts,
air conditioners in Texas, etc.) to obtain the macro energy savings. (See Figure
2.)
A macro supply curve of conserved energy offers two insights into the role of
energy efficiency. Is energy conservation worth pursuing? One can easily recog-
nize the overall significance of energy efficiency to present energy supplies by
comparing it to the potential savings to current use. Which measures save the
most and which are the cheapest? The relative importance of conservation
measures are shown both with respect to their potential contribution of energy
savings (the width of each measure’s step) and the relative costs (the height of
each measure’s step). The consistent accounting framework behind the supply
curve insures that the measures are indeed comparable.
Since it is impossible to measure each unit in a macro supply curve, statisti-
cal methods are needed accurately characterize each measure and the eligible
population. Such information is generally derived from surveys, the census, and
production data rather than simple engineering analyses. Further complications
are introduced if the stock of energy-using equipment is expected to change over
time due to retirements, standards, or population increase. All of these con-
siderations introduce new kinds of uncertainties. The accurate characterization
of the baselineS- often the baseline over time - becomes increasingly important.
Supply curves of conserved energy portray the technical potential for saving
energy but a more useful estimate is the amount of conservation that can be rea-
sonably achieved. It is possible to superimpose estimates of the fraction of the
stock that could be changed and the costs of the programs to reach them. Simi-
lar procedures can be used to gradually phase in conservation over several
years. Graphically, these actions result in a supply curve that is horizontally
squashed and above the original technical potentials curve. Again, the results
are easy to visualize and interpret.
Supply Curves - A Tool With Limitations
DRAFT
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-7-
The supply curve of conserved energy is popular because it is a simple way
to assess the potential for energy conservation the relative impacts of conserva-
tion measures. At the same time, the methodology has distinct limitations. Sup-
ply curves are often inappropriate when more than one fuel type is involved. In
electricity studies, the supply curve methodology cannot easily combine the
benefits of savings in energy and demand. The supply curve approach measures
savings from a baseline. If the baseline does not exist (or is poorly understood)
then it calculating savings from it is likely to generate large errors. For these (and
other) reasons, supply curves of conserved energy are probably best applied at
middle range of detail. For crude analyses, the curves do not provide any more
insights than, say, tables. For detailed studies, the limitations of the supply
curves prevent an integrated analysis.
Semantics
The “supply curve of conserved energy” is a misnomer, but has nevertheless
become the accepted term. It is not a supply curve in the traditional sense
because it is not a proven response; the market does not ofter the conserved
energy as the price of supplied energy varies. It is to some extent a price
schedule for a resource. Others prefer to call it a production function.
Bibliography
A. Meier, J. Wright, and A. H. Rosenfeld, Supplying Energy Through Greater Effi-
ciency, University of California Press, Berkeley and Los Angeles, CA (1983).
Northwest Power Planning Council, “Northwest Conservation and Electric Power
Plan”, Portland, OR (1986).
The Michigan Electricity Options Study, Department of Commerce, State of
Michigan, 1988.
D. B. Pirkey and R. M. Scheer, “Energy Conservation Potential: A Review of
Eight Studies,” Proc. of the ACEEE 1988 Summer Study on Energy Efficiency in
Buildings, Asilomar, CA (1988).
Meier, A., J. Wright, and A. Rosenfeld. “Supply Curves of Conserved Energy For
California’s Residential Sector.” Energy—The International Journal 7(1982): 347-
58
Meier, A. “Supply Curves of Conserved Energy.” Ph.D. Dissertation, Energy and
Resources Program, University of California, Berkeley, 1982.
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Figure 1. A hypothetiôaL.supply cUrve of conserved electricity.. Each step
represents a conservation measure. The width of the measure represents the
energy savings (in kWh/year), and the height indicates, the Cost of Conserved
Energy (CCE). A measure is cost-effective if its Cost of Conserved Energy is
less than the price of the energy it displaces. Thus, all measures below the
“Energy Price Line” are cost-effective. This is a “micro” supply curve, that is, for
one water heater, a refrigerator, or the space heating system in a house. A table
usually accompanies the supply curve, which includes a longer description of the
measure, its cost, energy savings, and CCE.
CCE
(c/kWh)
10
0 1000 2000 3000
Energy S plied Through Conservation
(kWh/year)
4000
DRAFT
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2 4 6 8 10 12
Cumulative energy supplied (TWh/year)
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-10-
2. METHODOLOGY
This section describes the method used to produce draft conservation sup-
ply curves for the residential and commercial sectors, sent to EPA on January
23-24. All costs of conser. ’ed energy, unless labeled as Technology Only,
include a 20% markup to account for implementation costs. This applies to all
figures.
2.1 Residential Sector.
The technology data base for the residential sector is the set of designs
identified for each appliance as part of the analysis of federal appliance energy
conservation standards. This data base is used by the LBL Residential Energy
Model (REM) which produces projections to the year 2030 of unit energy con-
sumption, annual sales of appliances, and total energy consumption for the U.S.
The base case projection from the LBL REM includes appliance standards
already on the books through 1988, affecting new appliances beginning in 1990.
(The most recent updates, which apply to refrigerators and freezers beginning in
1993, are not included.) The base case from which conservation potential was
assessed assumed efficiencies of new appliances frozen at the 1990 level. (A
base case in which efficiencies changed as a function of projected changes in
energy prices differs only slightly from the frozen efficiency case, since projected
electricity prices change lithe in the forecast period.)
The data for the conservation supply curves are produced by spreadsheets
containing the technology data base, in one case, and building shell measures, in
the other curve. These spreadsheets contain the same set of appliance designs
or shell measures as used in the LBL REM. They also take in projections of
appliances and number of houses in stock for a particular year from LBL REM.
Based on those projected.quantities, the possible energy savings and costs are
produced as a tabIe The measures are then ordered by ascending cost of con-
served energy. A graph is plotted from this table.
The graph shows, on the vertical axis, cost of conserved energy, expressed
as 1988 dollars per. million Btu (primary energy). For electricity, 11500 Btu = 1
kWh. The horizontal axis is energy savings, in units of trillion Btu (primary). The
energy savings are for measures implemented by the year indicated, accumu-
lated over the options possible. In other words, the cost of conserved energy is
obtained from the technology (or building shell) data base for each measure
beyond the base case. The energy savirigs for each measure are obtained as
DRAFT
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—11—
the difference between a base case projection of average unit energy consump-
tion (UEC) in stock and the UEC of a more efficient option in the data base, times
the number of appliances (or buildings) projected to be in stock in this year (2000
or 2010). Cumulative energy savings for the year are the sum over options.
Electricity and gas savings are presented on separate graphs for appliances.
For shell measures, separate tables and graphs are presented for electrically-
heated homes, and for gas-heated homes. For electrically-heated homes,
energy savings include both heating and cooling energy, where energy savings
are calculated as a weighted sum over technologies. For example, for cooling,
the technologies are room air conditioners, central air conditioners, and heat
pumps. Heating technologies are resistance and heat pumps. For shell meas-
ures applied to gas-heated dwellings, the cost of conserved energy attributes all
the costs to gas savings. Displayed in the tables, but not in the figures, are the
electricity savings in gas-heated homes, from effects of the shell measures on air
conditioning.
Cost of conserved energy for retrofit measures (to existing building shells)
has been estimated by assuming that the measures are applied to the entire
building stock. No consideration is given to constraints imposed by the normal
turnover rate of appliances or buildings, or by the rate at which retrofits have
occurred in the past.
2.2 Commercial Sector.
The technology data base for the commercial sector is the set of designs
identified for each end use and building type in the ACEEE report “The Potential
for Electricity Conservation in New York State”, (P.M. Miller, J.H. Eto, and H.S.
Geller, 1989). Only electricity is considered. This data base is used by the PNL
Commercial Energy Model (kept by D. Belzer) which produces projections to the,
year 2010 of end-use EUIs, annual floorspace by building type, and total energy
consumption for the U.S. The base case from which conservation potential was
assessed is the same as the “Where We Are Headed” scenario in the National
Energy Strategy paper (A. Carismith, et al, 1989. “Energy Efficiency: How Far
Can We Go 7’, ORNL/...) The base case in which efficiencies changed as a func-
tion of projected changes in energy prices differs only slightly from a frozen effi-
ciency case, since projected electricity prices change little in the forecast period.
The data for the conservation supply curves are produced by a spreadsheet
containing the technology and building shell data base. This spreadsheet
DRAFT
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-12-
contains the percent savings, by end use and building type, expected for each
measure, according to the New York study. The difference between those say-
ings and the base case savings are reported in the conservation supply curve.
The spreadsheet takes in projections of floorspace and EUI by building type from
the base case forecast. Based on those projected quantities, the possible energy
savings and costs are produced as a table. The costs of each measure are aver-
aged over the building types, weighted by energy savings, then placed in ascend-
ing order of cost of conserved energy, A graph is plotted from this table.
• The graph shows, on the vertical axis, cost of conserved energy, expressed
as 1988 dollars per million Btu (primary energy). For electricity, 11500 Btu = 1
kWh. Only electricity savings are on the graph. The horizontal axis is energy
savings, in units of trillion Btu (primary). The energy savings are for measures
implemented by the year indicated, accumulated over the options possible. In
other words, the cost of conserved energy is obtained from the technology (or
building shell) data base for each measure beyond the base case. The energy
savings for each measure are obtained as the difference between a base case
projection of energy utilization intensity (EUI) and the EUI of a more efficient
option in the data base, times the projected floorspace for the building type in this
year Cumulative energy savings for the year are the sum ovéroptions.
No attempt has been made to eliminate double-counting. The correction
factor would be the difference between the sum of energy savings due to upgrad-
ing space conditioning equipment and shell measures, and the cumulative effect
of upgrading space conditioning equipment and shell measures. We expect this
factor to be small.
Cost of conserved energy for retrofit measures (to existing building shells)
has been estimated by assuming that the measures are applied to the entire
building stock. No consideration is given to constraints imposed by the normal
turnover rate of equipment or buildings, or by the rate at which retrofits have
occurred in the past.
2.3 Administrative Costs •
In addition to technology costs, implementation of conservation measures
involves additional costs. The administrative costs of implementing any single
conservation measure depend upon the approach taken. For example, an
advertising campaign will incur different costs than an audit program, even if both
DRAFT
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-13-
are intended to increase the purchases of ceiling insulation.
No attempt was made to characterize the program costs appropriate to each
conservation measure here. However, it was felt inappropriate to completely
ignore program costs. Therefore, as an approximation to the average administra-
tive costs of all conservation measures, all costs of conserved energy were
increased by 20% (over the technology costs) to account for administrative costs.
3. TECHNOLOGY DATA BASE
The residential technology data base is comprised of the retail price, energy
efficiency, and unit energy consumption of alternative designs of residential appli-
ances (and building shells) used by the LBL Residential Energy Model for
analysis of DOE appliance performance standards. The technology data base
contains data for the following appliances:
o Electric appliances: central air conditioners, heat pumps, room air condition-
ers, incandescent lighting, water heaters, refrigerators, freezers, dishwashers,
clothes washers, clothes dryers, televisions, and pool controls.
o Gas appliances:furnaces, water heaters, and clothes dryers.
In the lexicon of DOE appliance standards, the technology data base for
each end use may be comprised of several product classes, each containing
many design options. For example, a product is a refrigerator. There are 7 pro-
duct classes for refrigerators and refrigerator/freezers, differing by the type of
defrost system (manual, partial, or automatic) the placement of the doors (freezer
on top, bottom, or side), and the presence or absence of through-the-door
features.
- manual defrost refrigerator,
- partial auto matic defrost refrigerator/freezer,
- top-mount auto-defrost refrigerator/freezer without through-the-door
features,
- top-mount auto-defrost refrigerator/freezer with through-the-door
features,
- side-by-side auto-defrost refrigerator/freezer without through-the-door
features,
- side-by-side auto-defrost refrigerator/freezer with through-the-door
features,
DRAFT
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14-
- botto rn-mount auto-dOfrost refrigerator/freezer.
A design option is a specific combination of components, differing in energy
efficiency. For each product class of refrigerators, there are 7 to 12 design
options applicable. Some of the design options considered for refrigerators and
freezers include:
- enhanced evaporator heat transfer,
- more efficient compressor,
- foam (to replace fiberglass) in refrigerator door,
- thicker insulation in doors,
- more efficient fan,
- thicker side and back insulation,
- evacuated panel insulation (replaces foam),
- two-compressor system,
- adaptive defrost.
The design options for other products are listed in the table of results for appli-
ances, ranked by cost of conserved energy.
Each design option stands as a conservation measure. If refrigerators in
place in 2000 were replaced with units characterized by lower unit energy con-
sumption, then the energy savings can be characterized as the difference in unit
energy consumption (between the average unit in stock and the design option
proposed as a conservation measure) times the number of units in stock. The
cost of conserved energy (CCE) associated with this conservation measure in the
CCE of the design option. Additional energy savings are calculated as the differ-
ence in UEC between design option with the next higher CCE and the previous
design option, again times the number of units in stock.
Building shell measures. In addition to replacing equipment, measures
which conserve energy by improving the thermal performance of building shells
are considered. These measures include’ increasing floor insulation (to R-1 9),
decreasing infiltration (to 0.4 air changes per hour (ACH)), increasing ceiling
• For refrigerators and freezers, all designs assume substitutes for chiorofluorocarbons.
The energy performance and costs of these substitutes are taken into account. (See U.S.
Department of Energy, Technical Support Document: Energy Conse,vation Standards for
Consumer Products: Refrigerators and Furnaces, DOEJCEO277, November, 1989.)
DRAFT
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-15-
insulation (to R-31, R-42, or R-50), increasing wall insulation (to R-1 1), and
increasing glazing (to triple-pane windows).
All building shell measures were applied to the average stock house in the
year indicated (either 2000 or 2010). In other words, all building shell measures
were handled as if they were retrofits, rather than identifying measures that could
be applied to new homes in the intervening years. In addition, Washington, D.C.
weather was assumed typical of national average weather.
Double-counting. When compiling a list of energy conservation measures
which mutually impact a particular end-use, such as space heating, the savings
attributed to any conservation measure must be corrected for any savings
already attributed to other measures previously implemented. For example, if
both a more efficient furnace, and increased ceiling insulation are potential con-
servation measures, they must be considered in order, and the energy consump-
tion adjusted to account for the effects of the first measure taken before calculat-
ing the energy savings from the second measure. Failure to follow this procedure
will lead to overestimating the total energy savings (called “double-counting”).
No corrections were made for double-counting in the commercial sector. In
the results reported here for the residential sector, the equipment measures were
generally observed to have lower CCE than the building shell measures. Conse-
quently, the energy consumption was corrected for equipment conservation
measures before calculating the CCE for the building shell measures. In other
words, the more efficient furnaces, air conditioners, and heat pumps were
assumed when calculating the additional savings possible from building shell
measures.
Commercial Sector. For the commercial sector, the set of potential energy
conservation measures was taken from a recent study forthe state of New York.*
4. CURRENT MARKET
The current market for residential appliances includes a range of efficiencies
available for purchase. Some appliances carry labels on each model showing the
efficiency or average operating cost, in order to provide information to pur-
chasers. Those appliances requiring such labels are shown in Table 1.
* P.M. Miller, J.H. Eto, and H.S. Gelter, “The Potential for Electricity Conservation in New
York State,” American Council for an Energy-Efficient Economy for the New York State
Energy Research and Development Agency, September, 1989.
DRAFT
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In addition, Table 1 indicates those appliances for which national energy per-
formance or efficiency standards have been promulgated. For some appliances,
there are both energy performance standards and labelling requirements.
DRAFT
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-17-
Table 1. REGULATED RESIDENTIAL APPLIANCES
Appliance Energy Standard Label
BOTH ENERGY STANDARDS AND LABELS
1. Refrigerators, freezers X X
2. Room air conditioners X X
3. Central air conditioners/heat pumps X X
4. Water heaters X X
5. Furnaces X X
6. Dishwashers X X
7. Clothes washers X X
ENERGY STANDARDS; NO LABELS
8. Clothes dryers X
9. Direct heating equipment X
10. Kitchen ranges and ovens X
11. Fluor’ scent light ballasts X
NO ENERGY STANDARDS; NO LABELS
12. Pool heaters
13. Televisions sets
14. Humidifiers and dehumidifiers
DRAFT
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For most appliances, trade associations publish directories listing charac-
teristics, including the energy efficiency of each model. From these directories,
one can determine the range of efficiencies currently available. Table 2 shows
the most efficient models available, for typical classes and sizes.
Table 2. Most Energy-Efficient Models
Refrigerator top freezer, 18.6 cu ft 840 kWh/yr
Freezer chest, manual defrost, 20.7 cu ft 528 kWh/yr
Dishwasher 574 kWh/yr
Clotheswasher front loading 451 kWh/yr
Clotheswasher top loading 651 kWh/yr
Water heater gas, 38 gallon .65 Energy Factor
Water heater electric, 50 gallon .96 Energy Factor
Water heater heat pump, 52 gallon 3.5 Energy Factor
Room air conditioner 10,100 Btwhr 12.0 EER
Central air conditioner 3 tons 15.0 SEER
Central heat pump 3 tons - 11.3 SEER
8.50 HSPF
Gas furnace 77,000 Btu/hr 96.0 AFUE (%)
5. PROJECTIONS
The supply curve of conserved energy for the residential sector was calcu-
lated from a frozen efficiency base case. Efficiencies of new units sold after 1990
were constant at the 1990 level, taking into account existing appliance standards
regulations. (The energy performance standard for 1993 refrigerators and
freezers was not included.) For the commercial sector, a base case from the PNL
Commercial Energy Model was used.
Business-as-usual efficiency improvements. In the commercial sector, the
business-as-usual penetrations of more efficient technologies are contained in
the base case. In the residential sector, the projection assumes that little
improvement beyond the mandatory energy performance standards will occur by
American Council for an Energy-Efficient Economy, “The Most Energy-Efficient Appli-
ances,” 1988 Edition, Washington, D.C.
DRAFT
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2010. This view is supported by comparing the frozen efficiency case to a
business-as-usual projection by the LB Residential Energy Model. Given current
EIA projections of residential electricity prices, which show little increase in real
price over time, the projection shows little increase in energy efficiency.
The LBL REM incorporates coefficients derived empirically from observed
market behavior over the past 15-20 years. Particularly in the area of energy effi-
ciency choice, there are a number of formidable market bamers. These are dis-
cussed in more detail elsewhere, but they include:
1. Indirect or forced purchase decisions (builders or landlords selecting appli-
ances for which they do not have to pay the operating costs, or emergency
replacements of malfunctioning equipment);
2. Lack of clear information about costs and benefits of energy efficiency
improvements;
3. Purchasers may lack sufficient capital to purchase more energy-efficient pro-
ducts;
4. Purchasers may have a threshold below which savings may not be significant
or worth the additional effort to obtain;
5. Highest efficiency designs may not be universally available, or may be bun-
dled with other features;
6. Manufacturers’ decisions to improve energy efficiency are often secondary to
other design changes, and may take years to implement;
7. Marketing strategies by manufacturers or retailers may intentionally lead to
sales of less effident equipment. V
Variations in energy prices or usage rates. Across the United States, there
are wide variations in the price of energy from locality to locality. According to a
recent projection, at the state residential electricity prices range from 4.5 cents
per kilowatthour in Idaho to 11.7 cents/kWh in New York. In addition, differences
in household size (persons per household), occupancy patterns (is the house
occupied during the day ?), and usage patterns (e.g., thermostat settings) lead to
wide variations in household energy consumption patterns. The analysis
H. Ruderman, M.D. Levine, and J.E. McMahon, “The Behavior of the Market for Energy
Efficiency in Residential Appliances including ating and Cooling Equipment,” in Energy
Systems and Policy,, volume 10,1987.
U.S. Energy Information Administration, “State Energy Price Projections for the Residen
tial Sector, 1989-1990,” EAFD/89-02, July, 1989.
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performed—to date assumes average energy prices, average usage behavior, and
average weather. A more detailed analysis is called for determine the differences
among regions. (LBL is engaging in such a study for 10 Federal regions in FY
1990.)
In addition, sensitivity analyses are needed to determine the range of cost of
conserved energy for each conservation measure, as a function of differences in
usage rates. These studies are most important where variation is the greatest,
and may be less important, although not negligible, for some end-uses where
usage behavior is less of a determining factor (e.g., perhaps refrigerators).
6. RESULTS: COSTS OF CONSERVED ENERGY
All costs of conseried energy, unless labeled as “Technology Only”, include
a 20% markup to account for implementation costs. This applies to all figures.
The costs of conserved energy for each of the conservation measures con-
sidered are presented in tables and figures. Table 3 and Figure 3 show the cost
of conserved energy for the commercial sector in 2000. (The cost of each meas
ure is averaged over all the building types.) Table 4 and Figure 4 show the cost of
conserved energy for the commercial sector in 2010.
Table 5 and Figure 5 show the supply curve of conserved energy for the
residential sector in 2000 for electric appliances. Table 6 and Figure 6 show the
supply curve of conserved energy for residential building shell measures in 2000
for electrically heated and cooled houses. Table 7 and Figure 7 show the supply
curve of conserved energy for the residential sector in 2000 for gas appliances.
Table 8 and Figure 8 show the supply curve of conserved energy for residential
buildingsheU measures in 2000 for gas heated houses.
Table 9 and Figure 9 show the supply curve of conserved energy for the
residential sector in 2010 for electric appliances. Table 10 and Figure 10 show
the supply curve of conserved energy for residential building shell measures in
2010 for electrically heated and cooled houses. Table 11 and Figure 11 show the
supply curve of conserved energy for the residential sector in 2010 for gas. appli-
ances. Table 12 and Figure 12 show the supply curve of conserved energy for
residential building shell measures in 2010 for gas heated houses.
DRAFT
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Table 3
Energy Supply Curve for Cormnercial Buildings in 2000
Technology
Energy Only
Saved CCE CCE
(TWh) (cent/kWh) (cent/kwh)
22.3 2.05 2.46
38.5 2.10 2.52
.4 2.40 2.88
8.1 2.47 2.96
102.9 2.51 3.01
4.]. 2.74 3.29
6.6 3.40 4.08
24.7 3.78 4.54
6.4 4.39 5.27
.7 4.60 5.52
3.6 4.72 5.66
.9 4.80 5.76
74 5.14 6.17
5.5 5.80 6.96
.1 6.20 7.44
12.9 6.46 7.75
311.7 TOTAL
high efficiency ballasts
reflectors for fluorescent lamps
re—set supply air temperature
economizer
adjustable speed drives for fan motors
energy saving fluorescent lamp
vav conversion
occupancy sensors
adjustable speed drives for pwnps
high efficiency fan motors
window films
refrigerator case covers
daylighting controls
re—size àhillers
high efficiency pump motors
very high efficiency lamps and ballasts
Energy Supply
Technology
Energy Only
Saved CCE CCE
(TWh) (cent/kwh) (cent/kwh)
27.8 2.03 2.44
46.1 2.10 2.52
.5 2.40 2.88
9.8 2.47 2.96
126.1 2.5]. 3.01
5.1 2.74 3.29
8.3 3.40 4.08
30.7 3.78 4.54
7.7 4.40 5.28
.9 4.60 5.52
4.5 4.72 5.66
.8 4.80 5.76
93.7 5.14 6.17
6.9 5.80 6.96
.2 6.20 7.44
15.1 6.54 7.85
384.2 Total
high efficiency ballasts
reflectors for fluorescent lamps
re—set supply air temperature
economizer
adjustable speed drives for fan motors
energy saving fluorescent lamp
vav conversion
occupancy sensors
adjustable speed drives for pumps
high efficiency fan motors
window film.
refrigerator case covers
daylighting controls
re—size chillers
high efficiency pump motors
very high efficiency lamps and ballasts
Technology
& Program
Table 4
Curve for Coxmnercial Buildings in 2010
Technology
& Program
-------
Conservation Supply Curve
Commercial Energy 2000
Cost of Conserved Energy (Cents/Kwh)
8
c — — —
— —
2
__; - -
0 - ___ -
0 50 100 150 200 250 300 350 400
Cumulative Energy Saved (TWh)
Figure 3
-------
Conservation Supply Curve
Commercial Energy 2010
Cost of Conserved Energy (Cents/Kwh)
8
2 . :
0 ----
0 50 100 150 200 250 300 350 400
Cumulative Energy Saved (TWh)
Figure 4
-------
Table 5
ResidentiaJ. Conservation Supply Curves 2000
ELectric Appliances
Technology Technology Per Unit Total Cun.
Only & Program Energy Energy Energy
UEC Consuner CCE CCE Savings Savings Savings
Appliance Level Design CkWh/y) SEER Price (S/MMBtu) (S/HMBtu) (MMBtu/y)(TBtu/y) (TBtuIy)
(Central Air 0 Baseline 2884.9 9.52 1607.00 NA NA NA WA WA
Dishwasher 0 Baseline 839.0 306.58 NA NA NA NA NA
Heat Purp 0 BaseLine 9867.8 9.46 1770.98 NA NA NA NA NA
Lighting 0 BaseLine 1000.0 4.72 NA NA NA NA NA
Electric Hot Water 0 Baseline 4157.1 89.1 280.46 MA NA NA NA NA
Electric Clothes Dryer 0 Baseline 988.0 158.00 311.60 MA NA NA NA NA
Chest Freezer -1 Stock Unit 578.7 149 347.02 NA NA NA NA NA
Pool Controls 0 Baseline 2500.0 0.00 0.00 NA NA NA NA NA
CLothes Washer 0 Baseline 926.1 190.00 380.04 NA NA NA NA NA
Room Air 0 BaseLine 569.7 8.72 382.00 NA NA MA NA NA
;Refrigerator -1 Stock Unit 1052 224.00 521.70 NA NA NA NA MA
Upright Freezer -1 Stock Unit 800.1 159 370.31 NA NA NA NA NA
Television 0 Baseline 205.0 158.00 362.50 NA NA NA NA NA
Clothes Washer I No Warm Rinse 814.0 190.00 380.04 0.00 0.00 1.29 111.1 111.1
Chest Freezer 0 Baseline 557.0 149.00 347.02 0.00 0.00 0.25 4.2 115.3
(Upright Freezer 0 BaseLine 797.5 159.00 370.31 0.00 0.00 0.03 0.4 115.7
‘Refrigerator 0 Baseline 955.0 224.00 521.70 0.00 0.00 1.12 128.1 243.8
‘Refrigerator I Erthanced Heat Transfer 936.0 224.10 521.94 0.11 0.13 0.22 25.1 268.9
Refrigerator 3 FO Door 878.0 225.55 525.10 0.46 0.55 0.67 76.6 345.5
‘Upright Freezer 2 4.50 C ressor 719.0 161.50 375.58 0.54 0.65 0.90 12.9 358.5
‘Chest Freezer 3 Foau Door 508.0 150.80 350.72 0.61 0.73 0.56 9.6 367.9
Heat Purp 4 Increase indoor coil circuits 8793.9 11.88 2050.00 0.63 0.76 6.00 51.7 419.6
Refrigerator 4 5.05 Coa ressor 787.0 228.95 532.33 0.67 0.80 1.05 120.2 539.8
Dishwasher 1 InVrove Food Filter 779.0 157.50 310.78 0.74 0.89 0.69 35.3 575.1
Upright Freezer 65.05 Conçressor 637.0 165.00 383.29 0.75 0.91 0.94 13.5 588.6
Central Air 4 Increase indoor coil circuits 2306.7 11.90 1730.00 0.85 1.03 4.42 126.1 714.7
ELectric Hot Water 3 2.0” Foam + Heat Trap 6116.2 90.0 284.00 0.90 1.08 0.47 19.5 734.2
Electric Clothes Dryer 2 Moisture Term 933.0 163.00 318.69 1.14 1.37 0.6 36.5 770.6
Chest Freezer 4 5.05 Coa ressor 462.0 154.30 357.99 1.27 1.52 0.53 8.8 779.5
Pool Controls 1 IlrOrove PooL Pu’p Controls 1600.0 50.00 100.00 1.38 1.65 10.35 9.6 789.1
Television 3 Introve CRT 171.0 161.75 369.90 2.32 2.78 0.06 6.5 793.6
Room Air 4 10.0 EER convressor 496.8 10.00 400.00 2.36 2.83 0.84 27.0 820.6
Television 1 Stanc y Power 2W 184.0 160.15 366.80 2.37 2.85 0.26 18.8 839.4
Upright Freezer 5 2” Door - 611.0 168.70 391.49 2.53 3.04 0.30 4.3 843.6
Refrigerator 5 2” Door 763.0 232.65 540.63 2.91 3.69 0.28 31.7 875.3
Upright Freezer 11 Evacuated Panels 423.0 209.10 477.28 3.02 3.63 137 19.6 894.9
Television 2 Reó ce Screen Power 5Z 176.0 161.45 368.90 3.04 3.65 0.09 7.2 902.1
Chest Freezer 11 Evacuated Panels 250.0 196.30 5.92 3.06 3.67 1.67 27.9 929.9
Lighting 1 HIgh Efficiency Incandescent 860.0 9.68 3.30 3.96 1.61 136.2 1066.1
‘Heat Pu’p 5 Increase outdoor coiL area 8497.1 12.11 2140.00 3.32 3.98 3.41 29.4 1095.5
Clothes Washer 2 Thermostatic Valves 761.0 203.00 399.00 3.54 4.25 0.61 52.5 1148.1
Dishwasher 2 IrtErove Motor 761.0 161.50 316.99 3.66 4.39 0.21 10.6 1158.6
Chest Freezer 7 2.5” Side Insulation 395.0 169.20 390.64 3.84 4.60 0.66 11.0 1169.6
Upright Freezer 8 2.5” Door 542.0 187.50 432.47 4.15 4.99 1.09 15.6 1185.2
Chest Freezer 5 2” Door 452.0 156.70 363.40 4.36 5.21 0.12 1.9 1187.1
Clothes Washer 3 In rove Motor 747.0 207.00 405.30 4.46 5.35 0.16 13.9 1201.0
Electric Clothes Dryer 3 1” Insulation 914.0 169.60 328.72 4.69 5.62 0.22 12.6 1213.6
Heat Purp 3 Increase indoor coil area 9315.5 10.13 2020.00 4.94 5.92 6.35 54.7 1268.4
Refrigerator 6 Efficient Fans 732.0 241.65 559.52 5.13 6.15 0.36 41.0 1309.3
Refrigerator 11 Evacuated Panels 577.0 287.65 656.18 5.25 6.30 1.78 204.8 1514.1
Central Air 3 Increase indoor coil area 2691.2 10.20 1700.00 5.26 6.31 2.23 63.6 1577.6
Upright Freezer 7 2.5’s Side InsuLation 557.0 185.00 427.01 5.28 6.33 0.62 8.9 1586.5
Refrigerator 8 3.0” Side Insulation 690.0 253.95 587.12 5.35 6.42 0.18 21.1 1607.6
‘Refrigerator 7 2.5” Side Insulation 706.0 249.10 576.95 5.66 6.77 0.30 34.3 1642.0
CDishwasher 3 In rove Fill Control 742.0 169.50 329.56 7.02 8.42 0.22 11.2 1653.2
.Electric Clothes Dryer 4 Recycle Exhaust 859.0 199.60 374.62 7.41 8.89 0.63 36.5 1689.6
(Electric Hot Water 4 Heat Recover Design 3300.0 900.00 7.85 9.42 9.39 389.3 2078.9
Room Air 5 Increase evaporator area 487.1 10.20 609.00 8.82 10.59 0.11 3.6 2082.5
Refrigerator 9 Two-Coaçressor System 607.0 303.95 692.07 10.64 12.77 0.95 109.6 2192.2
‘Refrigerator 12 Two-Coii ressor System 508.0 337.65 760.72 12.75 15.30 0.79 91.1 2283.3
Refrigerator 10 Adaptive Defrost 586.0 319.95 725.42 13.36 16.03 0.24 27.7 2311.1
Central Air 6 Increase outdoor coil tubes 2210.1 12.42 1890.00 14.50 17.40 0.61 17.3 2328.4
Refrigerator 13 Adaptive Defrost 490.0 353.65 794.04 15.57 18.69 0.21 23.8 2352.2
Heat Purp 6 Increase outdoor coil tubes 8710.2 12.42 2200.00 19.60 23.52 0.96 8.3 2360.5
Centrat Air 5 Increase outdoor coiL area 2263.0 12.13 1820.00 22.53 27.03 0.50 14.3 , 2374.8
Clothes Washer 4 Plastic Tub 743.0 213.00 414.83 23.59 28.31 0.05 4.0 2378.8
-------
Conservation
Supply
Residential Energy
Cost of Conserved Energy ($/MMBTU)
Curve
2000
Energy
Saved
(Quads)
Electric Appliances Only
40
30
20
10-
0
0 0.5
Cumulative
1 1.5 2 2.5 3 3.5 4 4.5
5
Figure 5
-------
Table 6
Residential Conservation Supply -- Building Shell
Electrically Heated and Cooled Houses
(Analysis based on Washington, 0,C.)
Heat Picp (9.66 SEER, 7.61 HSPF)
Central Air (11.9 SEER)
IfTprovemers 2000
Retrofit
Heating
Cooling
UEC
Energy
Total
Cua.
.
Cost
Energy
Energy
Energy
Saved
C E
Saved
Saved
Level
Retrofit
S
kWh
kWh
MMBtu
MMBTU/Y
S/HMBtU
TBtu/Y
TBtu/T
Heat Pu’p 1
Baseline
0.00
6741.559
2067.841
101.31
HA
Resistance 1
Baseline
0.00
12467.84
2118.147
156.90
HA
HA
HA
NA
Resistance 2
Floor, from no insulation to R-19
980.00
10274.34
2020.800
131.05
25.85
3.06
314.2
314.2
Resistance 3
InfiLtration, from 0.7 to 0.4 ACH
892.00
8379.228
1868.912
108.29
22.76
3.16
276.7
590.8
Resistance 4
Ceiling, from R-12.2 to R-31.2
713.00
7012.383
1812.990
92.90
15.39
3.73
187.0
777.8
Resistance 5
WaLls, from R-5.6 to R-11
547.00
6194.214
1153.616
82.43
10.48
4.21
127.4
905.2
Resistance 6
Windows, from 2 to 3 panes
526.00
5403.168
1692.170
72.94
9.49
4.47
115.3
1020.5
Heat PUTp 2
Floor, from no insulation to R-19
980.00
5535.670
1972.806
86.35
14.96
5.28
91.5
1112.1
Heat PUlP 4
Infiltration, from 0.7 to 0.4 ACH
892.00
3791.259
1769.931
63.95
12.48
5.76
86.7
1198.8
Heat PulP 3
Ceiling, from R-12.2 to R-31.Z
713.00
4822.012
1824.526
76.44
69.51
9.91
5.80
245.1
1443.8
Resistance 7
CeiLing, from R-31.2 to R-42.2
267.00
5123.295
1659,031
3.43
6.27
41.7
1485.5
Heat PulP 5
Walls, from R-5.6 to R-11
547.00
3312.143
1711,967
57.78
6.18
7.14
239.0
1724.5
Heat PuTp 6
Windows, from 2 to 3 panes
526.00
2883.949
1651,981
52.16
5.61
7.55
57.1
1781,6
Heat Purp 7
CeiLing, from R-31.2 to R-42.2
267.00
2132.130
1619.629
50.05
2.11
10.19
11.2
1792.8
Resistance 8
CeiLing, from R-42.2 to R-50.2
535.00
4995.309
1643.152
67.93
1.57
27.41
19.1
1811.9
Heat Purp 8
Ceiling, from R-42.2 to R-50.2
535.00
2663.293
1604.127
49.08
0.98
44.14
5.1
1817.0
-------
Conservation • Supply Curve
Residential Energy 2000
Cost of Conserved Energy ($/MMBTU)
70
60-
50
40-
30
20- -
1 _____________ ___ 2
Cumulative Energy Saved (Quads)
Shell Retrofit Electrically Heated Homes
j:jg t 6
-------
Table 7
Residential Conservation Supply Curves 2000
Gas Appliances
Technology Technology Per Unit Total C jn.
Only & Program Energy Energy Energy
UEC Consuner CCE CCE Savings Savings Savings
Appliance Level Design (kWhi’y) SEER Price (S/WMBtu) (S/MNBtU) (MMBtu/y)(T8 u,y) (TBtu/y)
57.8 76.5 2665.50 NA NA NA NA NA
17.5 360.00 MA NA NA ‘dA NA
4.00 170.00 340.03 NA NA NA NA NA
55.3 80.0 2669.00 0.12 0.15 2.5 116.7 116.7
3.52 183.00 358.70 3.62 4.35 0.2 3.2 119.3
3.72 173.00 351.60 4.22 5.06 0.3 4.4 124.3
48.1 92.0 3040.00 4.54 5.44 6.9 316.7 441.0
54.9 80.5 2689.00 5.17 6.20 0.3 15.5 456.9
15.8 70.0 510.00 10.4 .4 12.52 1.7 91.3 548.1
3.1.5 189.60 368.72 14.62 17.54 0.1 1.1 549.2
15.1 73.0 610.00 18.46 22.15 0.6 34.4 583.6
3.24 219.60 414.63 22.32 26.79 0.2 3.3 587.0
13.5 82.0 1010.00 28.83 34.60 1.7 88.1 675.1
Gas Furnace
Gas Not Water
Gas Clothes Dryer
Gas Furnace
Gas Clothes Dryer
Gas Clothes Dryer
Gas Furnace
Gas Furnace
Gas Not Water
Gas Clothes Dryer
Gas Not Water
Gas Clothes Dryer
Gas Not Water
0 BaSeline
0 Baseline
O Baseline
3 tn jced Draft
2 Moisture Term
I Te eratug Term
5 Condensing Neat Exchanger
4 Insulation
52.0” Foam. lID
3 1” Insulation
6 MultipLe Flues
4 Recycle Exhaust
7 Pulse Condensing
-------
Conservation
Supply
Curve
Residential Energy 2000
Cost of Conserved Energy ($/MMBTU)
0
0
Gas Appliances Only
1 1.5
Cumulative
2.5
Energy
(Quads)
40
30
20
10
0.5
_ __j_ --a---- -
2
3
3.5
4
Saved
4.5
5
Figure 7
-------
Gas Heat (92X cit.)
Air Conditioning (11.9 SEER)
Tab’e 8
Residential Con,.crvation Supply building Shell
Iwprovce cnts 2000
Ga heated hlOU .
(Anaty is ba cd on W .i hington, D.C.)
,
.
.
.
Retrofit
Heating
Cooling Gas Llcc.
Energy
Gas
tcc.
Energy
Gas
Elcc.
total
total
total
Cun.
Cun. Cun.
Cost
Energy
Energy Energy Energy Energy
Saved
Sovcd
Saved
CCE
CCE
CCE
Energy
Gas
lcc.
Energy
Gas Elcc.
level RETROFIt $
Iherms
kwh t4H8Iu IQ IOtu $MUtu
KliBtu/V
W4BIu/Y
1t148 1u/V
$/ 19481u
$/Pwiatu
$1 19481u
18w
IBtu
tUtu
tUtu
TUtu TUtu
Gas
Heat
I BaselIne 0.00
556.4701
2322.675 82.36 55.65 26.11
HA
NA
NA
NA
NA
NA
NA
WA
NA
NA
NA WA
Gas
heat
2 Floor, frc4u no instil. to R-19 980.00
458.4355
2216.842 11.34 45.84 25.49
9.13
8.16
0.91
8.65
9.68
81.11
169.1
134.3
34.8
169.1
134.3 34.8
Gas
Heat
3 CeilIng, from R12.2 to R31.2 713.00
399.8968
2051.225 63.58 39.99 23.59
6.39
4.81
1.52
8.99
11.80
31.71
367.1
313.3
54.4
536.8
447.6 89.2
Gas
Heat
4 tnt ill., from 0.1 to 0.4 ACH 892.00
315.2625
1990.633 54.42 31.53 22.89
7.60
7.06
0.56
9.46
10.21
128.95
472.9
453.0
19.9
1009.7
900.6 109.1
Gas
Heat
S Walls, from R S.6 to Rh 547.00
276.4718
1926.00? 49.80 21.65 2.15
3.82
3.23
0.59
11.53
13.66
74.13
228.8
207.6
21.2
1238.5
!108.2 130.3
Gas
Heat
6 Windows, from? to 3 panes 526.00
241.2076
1858.948 45.50 24.12 2!.38
3.55
2.93
0.62
11.94
14.45
68.7*
210.8
188.7
22.0
1649.3
1297.0
Gas
Heat
1 CeIlIng , R-42.2 267.00
228.5124
1823.401 43.82 22.85 20.91
1.38
1.06
0.33
15.55
20.37
65.79
79.6
61.9
11.7
1528.9
1364.9 1 M Q
Gas
Heat
8 Ceiling, R50.2 535.00
221.6596
1802.395 42.81 22.15 20.13
0.18
0.59
0.19
55.21
7347
223.10
44.6
37.7
6.9
1573.5
1402.7 170.9
-------
Conservation
Cumulative
Energy
Supply
(Quads)
Residential Energy 2010
Cost of Conserved Energy ($/MMBTU)
Curve
70
60
50
40
30
20
10
0
0
0.5 1 1.5 2
Shell Retrofit Electrically Heated Homes
Saved
Figure 10
-------
Residential Conservation Supply Curves 2010
Electrical Appliances
Technology Technology Per Unit Total CL .
oily & Program Energy Energy Energy
USC Consuner CCE CCE Savings Savings Savings
Appliance Level Design (kWh/y) SEER Price (S/NMBtu) (S/MNBtu) (MMBtu/y)(TBtuIy) (TBtu/y)
9.52 1788.37 NA NA NA NA NA
9.57 1554.17 NA NA NA NA NA
6.72 NA NA NA NA NA
158.00 362.50 NA NA NA NA NA
89.7 282.80 NA NA NA NA NA
8.91 379.76 MA NA NA NA NA
190.00 380.06 NA NA MA NA NA
0.00 0.00 NA NA NA NA NA
153.20 353.25 NA NA NA NA NA
150.00 307.74 MA NA NA MA NA
522.23 NA NA NA NA NA
380.67 NA NA NA NA MA
313.00 MA NA NA NA NA
380.06 0.00 0.00 1.12 108.7 08.7
525.10 0.46 0.55 0.61 76.7 185.4
2050.00 0.63 0.76 6.00 60.4 245.8
532.33 0.67 0.80 1.05 131.7 377.5
310.73 0.76 0.91 0.49 29.1 606.6
1730.00 0.85 1.03 4.42 153.9 560.5
383.29 0.90 1.08 0.27 4.1 564.7
284.00 0.91 1.09 0.16 7.5 572.2
100.00 1.38 1.65 10.35 10.5 !32.6
369.90 2.32 2.78 0.06 0.5 533.1
366.80 2.37 2.85 0.26 2.0 535.2
357.99 2.43 2.91 0.18 3.2 !38.4
391.49 2.53 3.04 0.30 6.6 573.0
540.63 2.91 3.49 0.28 34.7 eZ7.7
477.28 3.02 3.63 1.37 21.0 &7
368.90 3.06 3.65 0.09 0.8 6.9.5
400.00 3.18 3.82 0.70 25.5 t7’S.O
‘445.92 3.28 3.93 2.32 41.6 7 6.6
9.68 3.30 3.96 1.61 148.1 2.64.7
2140.00 3.32 3.98 3.41 36.6 39.1
399.00 3.54 4.25 0.61 59.1 ;58.2
316.99 3.66 4.39 0.21 12.3 ;70.5
390.64 3.84 4.60 0.66 11.7 !2.2
432.47 4.15 4.99 1.09 16.8 ;og.o
363.40 4.34 5.21 0.12 2.1 1.0
405.30 4.46 5.35 0.16 15.6 .:.66
318.69 4.59 5.51 0.13 8.3 :zs.o
328.72 6.69 5.62 0.22 16.4 39.3
2020.00 4.95 5.96 5.89 59.3 : 8.6
559.52 5.13 6.15 0.36 44.9 43.S
656.18 5.25 6.30 1.78 226.3 367.8
427.01 5.28 6.33 0.62 9.5 377.3
587.12 5.35 6.42 0.18 23.2 -.0.4
576.95 5.64 6.77 0.30 37.6 1.38.1
329.56 7.02 8.42 0.22 13.0 .51.1
374.62 7.41 8.89 0.63 41.6 6fl .7
900.00 7.85 9.42 9.39 445.6 33.4
409.00 8.82 10.59 0.11 4.1 62.A
1700.00 9.01 10.81 2.04 70.9 213.6
692.07 10.64 12.77 0.95 120.1 Z’33.5
760.72 12.75 15.30 0.79 99.8 U33.3
725.42 13.36 16.03 0.24 30.4 2263.7
1890.00 14.49 17.38 0.61 21.2 2254.9
794.04 15.57 18.69 0.21 26.0 2310.9
2200.00 19.60 23.52 0.96 9.7 2320.6
1820.00 22.55 27.06 0.50 17.5 2338.1
416.83 23.59 28.31 0.05 6.5 231.2.6
Table 9
Heat PuiV
Central Air Conditioner
Lighting
Color Television
Electric Water Heater
Roam Air Conditioner
Clothes Washer
Pool Controls
Chest Freezers
O isti washwr
Refrigerator
Upright Freezers
Electric Clothes Dryer
Clothes Washer
Refrigerator
Heat Pu!V
Ref rigerator
Dishwasher
Central Air Conditioner
Upright Freezers
Electric Water Heater
Pool Controls
Color Television
Color Television
Chest Freezers
Upright Freezers
Refrigerator
Upright Freezers
Color Television
Room Air Conditioner
Chest Freezers
Lighting
Heat P*rp
Clothes Washer
Dishwasher
Chest Freezers
Upright Freezers
Chest Freezers
Clothes Washer
ELectric Clothes Dryer
Electric Clothes Dryer
Heat Ptsp
Refrigerator
Refrigerator
Upright Freezers
Refrigerator
Refrigerator
Dishwasher
Electric Clothes Dryer
Electric Water Heater
Roam Air Conditioner
Central Air Conditioner
Refrigerator
Refrigerator
Refrigerator
Central Air Conditioner
Refrigerator
Heat PUYC
Central Air Conditioner
Clothes Washer
0 Baseline
0 Baseline
o Baseline
0 BaseLine
0 Baseline
0 Baseline
0 Baseline
0 Basslln.
0 Baseline
0 BaselIne
0 BaselIne
0 Baseline
0 Baseline
I No Warm Rinse
3 Foam Door
4 Increase Indoor coil, circuits
4 5.05 Caupressor
1 Ilprove Food Fitter
6 Increase Indoor circuits
4 5.05 C Vresscr
3 2.0 Fo Neat Trap
I Ipprove Controls
3 Ipprove CRT
1’ Stan y Power 2W
6 5.05 C tpressor
S 2 Door
5 2 Door
11 Ev.cuated Panels
2 Reóxe Screen Power 5
4 10.0 EER c pressor
11 Evacuated Panels
I High Efficiency Incandescent
S Increase outdoor coi I area
2 Thernestatic Valves
2 Ipprove Motor
7 2.5 Side Insulation
8 2.5 Door
5 2 Door
3 Inprove Motor
2 Moisture Term
3 1 Insulation
3 increase Indoor coil area
6 Efficient Fans
11 Evacuated Panels
7 2.5k Side Insulation
S 3.0w Side Insulation
7 2.5 w Side Insulation
3 Ipprov, Fill. Control
4 Recycts Exhauat
4 Heat Recovery
5 Increase evaporator area
3 Increase indoor coil area
9 Two-Coppressor System
12 Two-Coopressor System
10 Adaptive Defrost
6 Increase outdoor coi L tubes
13 Adaptive Defrost
6 Increase outdoor coil tubes
5 Increase outdoor coil, area
4 Plastic Tub
9827.4
2868.3
1000.0
205.0
4130.0
557.6
911.6
2500.0
477.7
821.5
931.0
660.4
944.0 159.00
816.0 190.00
873.0 225.55
8793.9 11.88
787.0 228.95
779.0 157.50
2306.7 11.90
637.0 165.00
4116.2 90.0
1600.0 50.00
171.0 161.75
186.0 160.15
462.0 154.30
611.0 168.70
763.0 232.65
423.0 209.10
176.0 161.45
496.8 10.00
250.0 196.30
360.0
8497.1 12.11
761.0 203.00
761.0 161.50
395.0 169.20
542.0 187.50
452.0 156.70
747.0 207.00
933.0 163.00
914.0 169.60
9315.5 10.13
732.0 261.65
577.0 287.65
557.0 185.00
690.0 253.95
706.0 249.10
742.0 169.50
859.0 199.60
3300.0
487.1 10.20
2691.2 10.20
607.0 303.95
508.0 337.65
586.0 319.95
2210.1 12.42
490.0 353.65
8710.2 12.42
2263.0 12.13
743.0 213.00
-------
Conservation
Supply
Residential Energy 2010
Cost of Conserved Energy ($/MMBTU)
Curve
0
0
Electric Appliances Only
Cumulative Energy
40
30
20
10
0.5 1 1.5 2 2.5 3 3.5 4 4.5 5
(Quads)
Saved
Figure 9
-------
table 10
Residential Conservation Supply -. Building Shell IrrVrovements 2010
Electrical ty heated and cooled homes
(Analysis based on Washington, D.C.)
Retrolit Heating Cooling Energy Total CUM.
Cost Energy Energy UEC Saved CCE Energy Energy
Level RETROFIT $ kWh kwh MMBtu MHBtu/Y S/MMBtu TBtu TBtu/Y
Heat Putp 1 Baseline 0.00 6681.19 2067.69 100.61
Resistance 1 BaseLine 0.00 12765.63 1824.73 158.45
Resistance 2 Floor, from no insulation to R-19 980.00 10519.75 1741.59 132.09 26.36 3.00 349.1 349.1
Resistance 3 CeilIng, from R-i2.2 to R-31.2 892.00 8579.36 1697.16 109.49 22.60 3.18 299.3 648.5
Resistance 4 Infiltration, from 0.7 to 0.4 ACH 713.00 7241.31 1563.88 93.26 16.24 3.54 215.1 863.6
Resistance 5 Watts, from R-5.6 to R-11 547.00 6342.16 1513.10 82.59 10.66 6.13 161.3 1004.8
Resistance 6 Windows, from 2 to 3 panes 526.00 5532.22 1460.42 72.94 9.65 4.39 127.8 1132.7
Heat PuTp 2 floor, from no insulation to R-19 980.00 5486.10 1972.66 85.78 14.84 5.32 98.9 1231.6
Heat Pu 4 InfiLtration, from 0.7 to 0.4 ACH 892.00 3757.31 1769.80 63.56 12.38 5.81 82.5 1314.1
Heat PuTp 3 CeiLing, from R-12.2 to R-31.2 713.00 4778.83 1824.39 75.94 9.84 5.81. 65.6 1379.7
Resistance 7 CeiLing, from R-31.2 to R-42.2 267.00 5245.66 1432.49 69.47 3.47 6.19 46.0 1625.7
Heat Ptvp 5 Watts, from R-5.6 to R-11 547.00 3282.48 1711.84 57.43 6.13 7.19 40.9 1466.6
Heat Pu , 6 Windows, from 2 to 3 panes 526.00 2858.12 1651.86 51.86 5.57 7.61 37.1 1503.7
Heat. PUIV 7 Ceiling, from R-31.2 to R-42.2 267.00 2708.26 1619.51 49.77 2.10 10.27 14.0 1517.7
Resistance 8 CeiLing, from R-42.2 to R-50.2 535.00 5114.62 1418.53 67.87 1.60 27.01 21.1 1538.9
Heat PurO 8 CeiLing, from R-42.2 to R-50.2 535.00 2639.45 1604.01 48.80 0.97 64.46 6.5 1545.3
Heat P*rV (12.11 SEER, 7.6 HSPF)
Electric Heat (11.9 SEER Air Conditioner)
-------
Conservation
Supply
Residential Energy 2010
Cost of Conserved Energy ($/MMBTU)
Cumulative
Shell Retrofit Electrically Heated Homes
Energy
(Quads)
Curve
70
60
50
40
30
20
10
0
0
0.5 1 1.5 2
Saved
Figure 10
-------
Table ii
Residential Conservation Sl.Cply Curves 2010
Gas Appliances
Technology Technology
Only & Program Per Unit Total Cue.
UEC Consueer CCE CCE Savings Savings Savings
Appliance Level Design (k Wh/y) Price ($/MM8tu CS/ Q48tu CMMBtU/y)(TBtU/y) (T3tu/y)
Gas Water Heater 0 Baseline 17.5 360.00 NA MA NA MA NA
Gas Clothes Dryer 0 Baseline 6.00 340.03 NA NA NA NA MA
Gas Furnace 0 Baselin. 55.4 2710.37 MA HA NA NA
Gas Clothes Dryer 2 Moisture Term 3.52 358.70 3.62 4.35 0.20 3.54 3.5
Gas Clothes Dryer I Tei erature Term 3.72 351.60 6.22 5.06 0.28 4.96 8.5
Gas Furnace 5 Cor ensing Heat Exchanger 48.9 3040.00 4.50 5 39 6.50 333.10 341.6
Gas Water Neater S 2.0 Foam • lID 15.8 510.00 10.26 12.31 1.75 97.98 439.6
Gas Clothes Dryer 3 1’ Insulation 3.45 368.72 16.62 17.54 0.07 1.26 o.a
Gas Water Neater 6 MultipLe Flues 15.1 610.00 18.46 22.15 0.65 36.30 477.1
Gas Clothes Dryer 4 Recycle Exhaust 3.26 414.63 22.32 26.79 0.21 3.72 480.8
Gas Water Heater 7 PuLse C ensing 13.5 1010.00 28.83 34.60 1.66 92.96 573.8
-------
Conservation
Supply
Residential Energy 2010
Cost of Conserved Energy ($/MMBTU)
Curve
0
0
Gas Appliances Only
Cumulative
Energy
(Quads)
40
30
20
10
0.5 1 1.5 2 2.5 3 3.5 4 4.5 5
Saved
Figure 11
-------
Residential Conservation Stçply -- luliding S$ .11 Zu wovu ents 2010
Gas Nealed Kc es
(Anatyils based on Itathington, D.C.)
1
RU1 IT
BaselIne
&strof It
Goat
S
5.00
NsatIs
Inery
1hcii
483.39033
Cooling
Energy
k ái
*837.13
£nefgy
bI 8tu
69.47
Gas
N4*tu
48.34
( Icc.
iStu
21.13
Energy
Raved
*Stu
Gas
Saved
i tu
(icc. Energy
Saved Cci CC I CCI
ii tu 8/ 1 1 18 W S/11 111u S/)SStu
Lnergy Gas (lee. Energy
Iltu Tills IStu TItu
645.2 597.0 48.1 645.2
Gas LI
TItu 1
597.0 1
2
3
4
floor, from no Insulation to 1-19
CeiL*ng, from 112.2 to 1-31.2
InfIltratIon, from 0.7 to 0.4 ACM
NO.00
713.00
892.00
398.23G3 1
347.37936
273.85992
1753.42
1622.43
1574.50
59.99
53.40
45.49
39.82
34.74
27.39
20.16
15.66
15.11
9.48
6.59
7.90
8.52
5.09
755
0.96 10.00 11.13
1.51 10.46 13.56 45.77
0.55 10.9* 11.73 156.51
*3.37 15.70 89.90
431.8 356.5 75.3
543.0 515.4 27.6
266.6 236.2 29.4
1077.0
1620.0
1085.6
953.5 1
1448.9 1
1705.2 11
‘5
* a1ls, from 5-5.6 to lii
547.00
24O 16351
1523.38
41.54
24.02
17.52
3.96
3.37
13.55 *6.60 53.40
245.3 214.8 30.S
2130.9
1919.9 21
6
l Icdows from 2 to 3 pones
526.00
209.53041
*470.34
37.86
20.95
16.9*
3.6?
3.(
0.32 15.10 23.41 79.85
93.5 77.3 16.2
2224.3
1997.2 Z
7
a
Ceiling 5-42.2
Gad (rig. 1-50. ?
267.00 198.50249
535.00 *92.37587
*442.23
1423.6*
36.44
35.63
19.85
19.24
*6.59
16.39
1.43
0.80
0.6*
0.19 64.37 64.45 270.78
52.5 43.0 9.6
2276.8 2040.2 21
-------
Conservation Supply Curve
Residential Energy 2010
Cost of Conserved Energy ($/MMBTU)
100— —
90
80
70
60
50
40
30
20” _
Cumulative Energy Saved (Quads)
Sheil Retof It Gas Heated Homes
-------
ATTACHMENT F
Reforestation Analysis
06W0658C
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Attachment F
Carbon Uptake Through Reforestation
Carbon dioxide is fixed by trees during photosynthesis. A similar, but
opposing process, called respiration, results in the emission of CO 2 . The net
result during the life of the tree is negative, carbon is added to the tree’s
mass during growth. However, carbon emission continues after death as the
tree decays. If the decay period of the life cycle of the tree is stopped
(i.e. trees are harvested and used to build long-lasting products) or, as with
the harvesting of short-rotation trees, carbon is stored in the root system
which lives as the tree grows back, then the tree can contribute a net
negative effect on CO 2 emissions. Thus, tree planting with appropriate
management practices can reduce atmospheric carbon dioxide levels.
This tree planting program is assumed to take place over and above any
other reforestation efforts. Thus, the gains in carbon sequester.ed under this
program can be subtracted from total CO 2 emissions because it leads to an
increase in the size of the carbon sink. The base case change in sink size
caused by existing reforestation activities between 1990 and 2010 is assumed
to be zero. This assumption, however, requires further examination.
An estimate has been made of the cost of a tree planting program on
marginal crop and pasture land and unstocked forest land in the United States
and the amount of carbon dioxide that can be expected to be sequestered by
such a program. This program takes into account differences in land type and
region that affect growing rates and what tree species can be best planted in
that situation. Data on available land, rental rates, planting and treatment
costs, and carbon sequestration rates for each region and land type have been
calculated in a working paper being prepared for the EPA by Bob Moulton (U.S.
Forest Service) and Ken Richards (formerly Council of Economic Advisors)
(Moulton and Richards 1989). It should be emphasized that this is a draft
report
Land Enrolled
In the Moulton and Richards report, the country was divided into ten
regions and available land was identified as being crop, pasture, or forest
land. The amount of land potentially available for a tree planting program
was calculated from U.S. land surveys which identified highly erodible, poor
quality or wet crop and pasture land and from SCS/NRI reports of forest land
being under-utilized. 344 million acres fell into these categories and were
classified as land which could potentially be used in a national tree planting
program. These land areas were then further characterized as being either wet
or dry (not wet), in the case of crop and pasture, or, in the case of forest
land, as being better suited to a planting program or either an active or
passive management program.
It is assumed in this strategy that up to 3.5 million acres are
reforested each year with the program beginning in 1992. Since it will most
likely take some time for the program to come up to speed (Moulton 1990), it
is assumed that the planting will start at 1 million acres in 1992, and
1
-------
increase to 1.5M in 1993, 2.0M .in 1994, 2.5M in 1995, 3.0Mm 1996, 3.5M 7 in
1997. Plantings will then .remain at 3.5M for the remaining years until about
60 million acres have been planted by about the year 2010 (see attached
spreadsheets). A presentation of the total land enrolled in each region
through 2000 and 2010 is included in Exhibit 1. Appendix A contains a
breakdown of enrollment by region and land type/quality.
Carbon Sequestration
Incremental carbon capture (sequestration) per acre was calculated for
each of the regions and land types/qualities outlined above by Moulton.
Region specific factors for the conversion of annual increases in merchantable
wood to total forest carbon sequestration were supplied to Moulton by Richard
Birdsey. The weighted average sequestration rate for all land enrolled by
2000 is 1.81 metric tons of carbon per acre per year (see attached spreadsheet
#1).
Higher sequestration rates may be achievable in the future with use of
better genetically-engineered trees. However, the adoption rate for these
new strains may take decades (Moulton .1990). Since the time it takes to
determine the impact is long and the down-side risks of errors are great,
foresters tend to be cautious about major experimentation. It is assumed that
a 25% increase in existing sequestration rates may be achieved for trees
planted beginning in the year 2000. The weighted average sequestration rate
for trees planted after 1999 is expected to be 2.26 MT Carbon/Acre/Yr (see
attached spreadsheet #2).
The carbon uptake for a forest varies according to the age of the trees
planted. Incremental carbon sequestration of a forest over time (starting
from original planting to full maturity) generally follows a sigmoid . curve
pattern that can be approximated as linear. Based on examination of marginal
growth curves (supplied by Bob Moulton), we have assumed that sequestration
rates increase linearly, from zero to the average rates presented above,
between years 1 - 10 of the stands lifetime. The stand is assumed to continue
to sequester carbon at the average rate throughout the next eight years of
this analysis.
2
-------
Costs and Revenues
Rental rates were based on rates paid out under the Conservation Reserve
Program (CRP)’ during past signups. Rental rates were adjusted upward to
reflect the fact that the most eager renters had already taken part in the
program and were further adjusted for areas with high land values. The
resulting rental rates for each region and land type are listed in the
attached worksheet (Moulton and Richards 1989). Rent is expected to be paid
on enrolled land for a total of 10 years from signup. It is expected that
very little land will be converted to other uses (like reconversion to crop
land) after this time (Moulton 1990).
Treatment costs include the cost of preparing the land for planting,
planting the trees (including the cost of seedlings), and maintenance of the
stand. They, too, were calculated by Moulton and Richards in their draft
study. Treatment costs were annualized over 40 yrs at a discount rate of 7%.
It is not likely that there would be revenues from the sale of timber by
either 2000 or 20l0’due to the long period of time it takes for a forest to
reach a point at which it can be harvested. Additionally, this program would
involve numerous landowners each enrolling relatively small tracts of land
which would less likely be economical to harvest commercially.
Results
Reforestation of 59 million acres as outlined above at sequestration
rates of 1.81-2.26 MT Carbon/Acre/Yr should fix 78 - 87 million MT Carbon/Yr
in 2010 at a totalánnual cost of $1.2 billion. The weighted average land
rental costs is $23.48/acre/yr and treatment costs annualized over 40 years at
7% is $6.65/acre/yr. The average unit cost of carbon sequestration under this
program is about $14 - 15 per MT Carbon/Yr in 2010. Exhibits 1 and 2 present
these results for 2000 and 2010 for current and genetically-improved
sequestration rates, respectively.
For comparison, Shame Tyson (SERI) has calculated that a national tree
planting program on public and private land could sequester 80-100 million
tons carbon at a unit cost of $5-16/ton/year, however the inputs and
calculations themselves are not available (Tyson, 1989).
Low Cost vs. High Cost
For purposes of inclusion in the CO 2 reduction cost study being prepared
by EPA, results of this analysis have been calculated for low and high cost
1 The CRP program is administered by the USDA to take annually tilled
marginal crop land out of production for periods of ten years. Rent is paid
to the landowners to offset opportunity costs lost. Land which qualifies for
this program is generally highly erodible and one of the requirements of the
CRP program is that soil management practices must be implemented. Planting
trees is one way to satisfy the requirement that a permanent cover crop be
planted to prevent.soil erosion.
‘3
-------
subgroups. Rows in the attached spreadsheets were sorthd from low to high by
2010 unit cost. The spread heet was divi4èd into low and high cost groups
based on cumulative carbon sequestration. •Each group includes roughly 50
percent of the total carbon sequestered. In 2010, under the genetically-
improved scenario, the low cost group totals 44 million tons of carbon and the
high cost group accounts for 43 million tons.
Low Cost Results
In the low cost group, reforestation of 29 million acres should fix
40 - 44 million MT Carbon/Yr in 2010 at a total annual cost of $413 million.
The average unit cost of carbon sequestration under this program is about
$9.35/MT carbon/yr in 2010 assuming genetic improvements on trees planted
after the year 1999; assuming no genetic improvements, the average unit costs
are $10.39/MT carbon/yr in 2010. Exhibits 1 and 2 present these results for
2000 and 2010 for current and genetically-improved sequestration rates,
respectively.
High Cost Results
In the high cost group, reforestation of 30 million acres should fix
39 - 43 million MT Carbon/Yr in 2010 at a total annual cost of $802 million.
The average unit cost of carbon sequestration under. this program is $18.67/MT
carbon/yr in 2010 assuming genetic improvements on trees planted after the
year 1999; assuming no genetic improvements, the unit carbon costs are
$20.74/MT carbon/yr in 2010. Exhibits 1 and 2 present these results for 2000
and 2010 for current and genetically-improved sequestration rates,
respectively.
4
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EXHIBIT 1
Results wIth Current Sequestration Rates
TOTAL TOTAL TOTAL TOTAL TOTAL TOTAL UNIT UNIT
LAND LAND COST COST CARBON CARBON COST COST
CA 000) (A 000) (S 000) (5 000) CT/V 000)(TIY 000) (S/T/Y) ($/T/Y)
2000 2010 2000 2010 2000 2010 2000 2010
REGION TYPE
NORTHEAST 1,010 2,482 21,656 38,078 618 2,671 $35.06 $14.26
LAKE STATES 953 2,343 15,467 28,391 955 4,131 516.19 $6.87
CCRNBELT 815 2,005 9,658 16,689 425 1,836 $22.75 $9.09
NORTH PLAINS 205 511 3,786 6,892 190 320 $19.96 $8.40
APPALACHIA 2,242 5,512 67,705 110,749 2,009 8,690 $33.70 $12.74
SOUTHEAST 1,488 3,657 35,790 58,339 1,151 4,978 $31.09 $11.72
DELTA STATES 1.305 3,205 16,738 28,979 839 3,627 519.96 $7.99
SOUTH Punts 1,543 3,793 30,500 50,592 1,285 5,557 $23.74 $9.10
MOUNTAIN 457 1,124 16,989 23,831 546 2,361 $27.46 $10.09
PACIFIC 1,887 4,640 23,665 49,966 1,159 5,013 $20.42 $9.97
TOTAL 11,905 29,276 5239,953 5412,506 9,175 39,683 $26.15 $10.39
41GM TOTAL TOTAL TOTAL TOTAL TOTAL TOTAL UNIT UNIT
LAND LAND COST COST CARBON CARBON COST COST
CA 000) (A 000) (S 000) (5 000) CT/V 000)(T/Y 000) (S/T/Y) (S/T/Y)
2000 2010 2000 2010 2000 2010 2000 2010
REGION TYPE
NORTHEAST 397 976 22,133 35,620 357 1,545’- 561.97 523.06
LAKE STATES 674 1,164 34,539 54,124 692 2,991 549.94 518.10
CCRNBELT 2.265 5.575 165,921 268,020 2,603 10,393 569.05 525.79
NORTH PLAINS 459 1,129 27,219 43,035 522 2,237 $52.16 $19.07
APPALACHIA. 2,583 6,349 58,691 99,767 1,235 5,340 $47.54 $18.68
SOUTHEAST 2,626 6,455 56,116 101,950 1,406 6,080 539.92 $16.77
DELTA STATES 1,631 4,009 66,034 105,476 1,375 5,947 $46.57 $17.73
SOUTH PLAINS 706 1,735 20,843 36,080 463 2,003 $45.01 $18.01
MOUNTAIN 432 1,062 4,220 7,285 80 345 $52.96 S21.14
PACIFIC 517 1,271 29,608 50,612 407 1,762 $72.66 $28.72
TOTAL 12,092 29,726 $483,324 $801,968 8,939 33,662 $54.07 $20.74
ALL TOTAL TOTAL TOTAL TOTAL TOTAL TOTAL UNIT UNIT
LAND LAND COST COST CARBON CARBON COST COST
(A 000) (A 000) (S 000) (5 000) CT/V 000)(T/Y 000) ($/TIY) (S/T/Y)
2000 2010 2000 2010 2000 2010 2000 2010
REGION TYPE
NORTHEAST 1,407 3,458 43,789 73,698 975 4,216 544.92 $17.48
LAKE STATES 1,426 3,507 50,006 82,515 1,647 7,122 530.37 $11.59
CORNBELT 3,083 7,580 175,579 284,709 2,827 12,229 $62.10 $23.28
NORTH PLAINS 667 1,639 31,005 49,927 711 3,077 $43.58 $16.23
APPALACHIA 4,325’ 11,861 126,396 210,516 3,244 16,030 $38.96 $15.01
SOUTHEAST 4,113 10,112 91,906 160,289 2,557 11,058 535.95 $14.50
DELTA STATES ‘ 2,936 7,217 80,772 134,455 2,214 9,574 $36.49 $14.04
SOUTH PLAINS 2,248 5,527 51,343 86,672 1,748 7,559 $29.37 $11.47
MOUNTAIN 889 2,187 19,209 31,116 626 2,705 $30.71 $11.50
PACIFIC 2,405 5,911 53,273 100,578’ 1,566 6,775 $34.01 514.85
TOTAL 24,000 59,000 $723277 $1,214,474 18,116 78,345 539.93 515.50
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EXHIBIT 2
Resufts with Genetically-Improved Sequestration Rates
TOTAL TOTAL TOTAL TOTAL TOTAL TOTAL UNIT UNIT
LAND t.AND COST COST CARBON CARSON COST COST
CA 000) (A 000) (S 000) (S 000) (TI ’ ? 000)(T/Y 000) (S/TI’?) (S/T/ ’ ?)
2000 2010 2000 2010 2000 2010 2000 2010
REGION TYPE
NORTHEAST 1,010 2,482 21,656 38,078 623 2,968 S34.76 $12.83
LAKE StATES 953 2.343 15,467 23,391 963 4,590 516.05 $6.19
CORNBELT 815 2,005 9,658 16,689 428 2,041 $22.55 $8.18
NORTH PLAINS 208 511 3,736 6,892 191 911 $19.79 $7.56
APPALACHIA 2,242 5,512 67,705 110,749 2,027 9,657 533.40 $11.47
SOUTHEAST 1,488 3,657 35,790 58,339 1,181 5,532 $30.82 $10.55
DELTA STATES 1,305 3,208 16,738 23,979 846 6,030 $19.79 $7.19
SOUTH PLAINS 1,543 3,793 30,500 50,592 1,296 6,175 $23.53 $8.19
MOUNTAIN 457 1,126 16,989 23,831 551 2,623 527.22 $9.08
PACIFIC 1,887 4,640 23,665 49,966 1,169 5,570 $20.24 $8.97
TOTAL 11,908 29,274 $239,953 $412,506 9,256 64,099 $25.93 $9.35
NIGH TOTAL TOTAL TOTAL TOTAL TOTAL TOTAL UNIT UNIT
LAND LAND COST COST CARBON CARBON COST COST
CA 000) CA 000) (S 000) $ 000) (TI’? 000)(T/Y 000) (S/TI’?) (S/T/’?)
2000 2010 2000 2010 2000 2010 2000 2010
REGION TYPE
NORTHEAST 397 976 22,133 35,620 360 .1,717 $61.43 $20.75
LAKE STATES 474 1,164 34,539 54,124 698 3,324 $49.51 $16.23
CCRN BELT 2,268 5,575 165,921 268,020 2,424 11,569 568.45 $23.21
NORTH PLAINS 459 1,129 27,219 43,035 526 2,508 $51.71 $17.16
APPALACHIA 2,583 6,349 58,691 99,767 1,245 5,934 $47.13 $16.81
SOUTHEAST 2,626 6,455 56,116 101,950 1,418 6,756 539.57 $15.09
DELTA STATES 1,631 4,009 66,034 105,476 1,387 6,609 $46.16 $15.96
SOUTH PLAINS 706 1,735 20,843 36,080 467 2,226 $44.62 $16.21
MOINTAIN 432 1,062 6,220 7,285 80 383 $52.50 $19.02
PACIFIC 517 1,271 29,608 50,612 411 1,958 $72.03 $25.84
TOTAL 12,092 29,726 $683,324 $801,968 9,017 42,966 $53.60 $18.67
ALL TOTAL TOTAL TOTAL TOTAL TOTAL TOTAL UNIT UNIT
LAND LAND COST COST CARBON CARBON COST COST
(A 000) (A 000) (S 000) (5 000) CT/V 000)(T/Y 000) (S/TI’?) (S/Ti’?)
2000 2010 2000 2010 2000 2010 2000 2010
REGION TYPE
NORTHEAST 1,407 3,458 43,789 73,698 983 4,685 546.53 $15.73
LAKE STATES 1,426 3,507 50,006 82,515 1,661 7,914 $30.10 $10.43
CORN BELT 3,083 7,580 175,579 234,709 2,852 13,590 $61.56 $20.95
NORTH PLAINS 667 1,639 31,005 49,927 718 3,419 $43.20 $14.60 0
APPALACHIA 4,825 11,861 126,396 210,516 3,272 15,591 538.63 $13.50
SOUTHEAST 4,113 10,112 91,906 160,289 2,579 12,288 535.63 $13.04
DELTA STATES 2,936 7,217 80,772 134,655 2,233 10,640 $36.17 $12.64
SOUTH PLAINS 2,268 5,527 51,343 86,672 1,763 8,401 $29.12 $10.32
MOUNTAIN 889 2,187 19,209 31,116 631 3,006 $30.44 $10.35
PACIFIC 2,405 5,911 53,273 100,578 1,580 7,529 $33.71 $13.36
TOTAL 24,000 59,000 $723,277 $1,214,476 . 18,273 87,063 $39.58 $13.95
-------
A.e.r rL 4I pr.a
Buchanan, S., 1989. “Costs of Mitigating Greerthouse Effect for Generic Coal-,
Oil-, and Gas-Fired Plants.” Prepared for USEPA.
Marland, Gregg, 1989. “The Prospect of Solving the CO 2 Problem through Global
Reforestation.” Prepared by the Oak Ridge National Laboratory for DOE.
Moulton, Robert and K. Richards, 1989. Working paper for USFS stuldy of
reforestation programs.
Tyson, K. Shame, 1989. “Agriculture and Land Use.” Prepared for inclusion
in Carbon Dioxide Inventory and Policy Study . Prepared for Office of
Environmental Analysis, U.S. Department of Energy.
USDA, 1989. “Tree Planting Implementation Options.” Economics and Research
Service.
USEPA, 1989. “Policy Options for Stabilizing Global Climate.” Draft Report
to Congress.
USFS, 1989. “Tree Planting and Forest Improvement To Reduce Global Warming.”
USFS, 1988a. “The South’s Fourth Forest: Alternatives for the Future.”
USFS, 1988b. “Timber Sale Program Annual Report: Fiscal Year 1988 Test -
National Summary.”
7
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APPENDIX
Land Enrollment by Region and Land Type
Since the CRP is an incentive program run by the government,
participation by landowners is voluntary. It is important to note that it is
not expected that all 344 million acres will be enrolled, but that these acres
represent the land which qualifies for the program. Due to the long term
effect of tree planting on the availability of alternative land uses it is
probably the case that a greater percentage of pasture and forest land would
be enrolled in this program than crop land. By planting trees on crop land
the farmer forgoes the opportunity to plant food crops, should demand rise in
the future. Additionally, due to the high rental costs of crop land, it is
more cost effective to plant on non-crop land for carbon sequestration. There
are pronounced regional differences in unit costs of carbon sequestering
(—$/ton of carbon/year) resulting from variation in rental and treatment costs
and sequestration rates.
Traditional low éost regions, including the Pacific, Southeast, Delta
States, Appalachia, and Southern Plains either have lowrental rates (low.
opportunity costs) or high sequestration rates (forest stands grow quickly),
and would thus be more likely to be enrolled in a tree planting program. The
remaining regions, including the Northeast, Mountain, Lake States, North
Plains, and Cornbelt either have higher costs or lower average sequestration
rates.
We assume that 10% of the crop land, 40% of the pasture land, and 55% of
the forest land that qualify for this program in the low cost regions will
actually be enrolled. The percent enrolled for each land type in the
remaining regions is assumed to be half that of the low cost regions, that is,
.5%, 20%, and 27.5%, for crop, pasture, and forests, respectively. Based on
these assumptions a proportion was calculated for each type and quality of
land to be applied to the total enrolled each year (1 million acres in 1992,
1.5 million acres in 1993, et cetera). Of the 59 million acres enrolled in
this program through 2010, 14 million acres are crop land, 12 million acres
are pasture, and 33 million are forest land. Please refer to the attached
spreadsheet for the total amount of land enrolled in each region and land
subgroup for the years 1992-2010.
8
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CFC Phase-Out Analysis
06W0658C
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Attachment G
Costs of Phasing Out CFCs on a Carbon Dioxide Equivalent Basis
The purpose of this attachment is to (1) discuss conceptual issues
associated with presenting estimates of CFC phaseout costs and emission
reductions in the years 2000 and 2010 as requested for the warming cost study
(hereafter referred to as the “cost study”); (2) describe the methodology used
to calculate the costs in 2000 and 2010; and (3) present a brief sUmmary of
the results.
I. CONCEPTUAL ISSUES
The general framework adopted in the cost study is to calculate the
costs of introducing controls and the emission reductions resulting from their
implementation for a given year (e.g. 2000 or 2010). However, because of the
nature of the proposed regulation mandating a CFC and halon phaseout, and the
nature of CFC and halon consuming equipment, providing such estimates is
difficult.
The proposed rule for a CFC and halon phaseout mandates that the
Droduction of CFCs and halons be phased out by the year 2000. The rule does
not, however, place any restrictions on CFC emissions. As a result, the
modelling framework used calculates the cost to industry of reducing CFC and
halon use to levels that comply with the production phaseout. Because of the
nature of CFC equipment, reductions in the use of CFCs in a given year do not
necessarily translate into reductions in CFC emissions in that same year.
This is because many of the types of equipment contaIn a CFC or halon charge
that can remain in the equipment for decades. Indeed, this charge may leak
slowly over time, may be vented at servicing or disposal, or may be collected
for recycling purposes. This “banking” of CFCs and halons in equipment
complicates the calculation of costs and actual emission for a given year
because the emission reductions for that year result at least partially from
controls implemented (and costs incurred) in previous years.
Given these complications, two differ i approaches are used to adapt to
this cost study the CFC and halon phaseout cost and emission reduction
estimates contained in EPA’s CFC and halon Phaseout Report. The first
approach calculates the total costs of the phaseout and the total reductions
in CFC and halon use in the years2000and 2010. This approach assumes
emission reductions occur immediately; hence it ignores the “banking delay”.
As a result, this approach will tend to underestimate the costs per unit of
emission reduction since it overestimates the emission reduction achieved.
The second approach calculates the total cost of the phaseout and the total
actual reductions in CFC and halon emissions in the years 2000 and 2010. This
approach will tend to overestimate the cost per unit of emission reduction
because (1) controls in 2000 and 2010 affect emissions in many subsequent
years; and (2) a portion of the actual emission reductions in 2000 are due to
1
-------
control actions undertaken in prior years in which a phaseout was .not.
required.
2. METhODOLOGY
To apply the two approaches described above requires the following
estimates:
• the total cost of a CFC and halon phaseout in the years 2000 and
2010;
• the total reduction in CFC use in 2000 and 2010 (method 1) and the
total reduction in CFC emissions in 2000 and 2010 (method 2);
In addition, to correctly calculate the impact on warming of a CFC and
halon production phaseout requires consideration of two other factors. First,
many of the substitutes for CFCs and halons are themselves greenhouse gases
(e.g., HCFCs and HFCs), and hence the impact of their increased used must be
included in an analysis of the effect of a CFC and halon phaseout on warming.
Second, many of thc substitute chemicals for CFCs and halons may affect the
energy efficiency of the equipment in which they are used. This will have a
secondary impact on global warming because of changes in emissions of trace
gases, such as carbon dioxide, associated with energy production.
A list of the controlled CFC and halon compounds, the HCFC and HFC
substitutes and the energy-related trace gases that are included in the
analysis are presented in Exhibit I along with the mass-based global warming
potentials (GWPs) used in this study.
The CFC and halon Phaseout Report estimated emission changes for each of
the above compounds. A detailed description of the framework can be found in
the Phaseout Report; 2 the remainder of this section will briefly summarize the
approach.
1 Prior to the year 2000, CFC and halon use is restricted to use levels
required under the Montreal Protocol. As a result, a portion of emission
reductions in 2000 and 2010 will be due to control actions that were
implemented to achieve less than a complete phaseout.
2 wCosts and Benefits of Phasing Out Production of CFCs and Flalons in
the United States, Office of Air and Radiation, U.S. EPA, November 3, 1989.
2
-------
• EThIBIT I. List of Greenhouse Gases Included in Current CFC Analysis
Comtound Global Warming Potential 3
A. Controlled Compounds
CFC-ll 3500
CFC- 12 7300
CFC-113 4200
CFC-114 6.900
CFC- 115 6900
Halon-130 1 5800
B. Substitute Compounds
HCFC-22 (substitute) 1500
HCFC-123 85
HCFC- 124 430
HFC .l25 2500
HFC -134a 1200
HCFC- 14 1b 440
HCFC-142b 1600
HFC- 143a 2900
HFC- 152a 140
C. Energy-Related Trace Gases
C02 1
CH4 21
NOx 40
CO 3
D. Other Compounds in Baseline
(No Reductions from No Controls Case)
Methyl Chloroform 100
Carbon Tetrachioride 1300
HCFC-22 (baseline) 1500
Source of GWPs: IPCC, Section 2: Radiative Forcing of Climate. 27 April
1990.
GWPs are expressed on a C0 2 -equivalent basis for a 100-year time
horizon.
3
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The PhaseoutReport estimated the costs, CFC and halon emission
reductions, increases’in chemical substitute use, and changes in energy use
resulting from a phaseout of CFCs and halons in the United States by 2OOO.
These were estimated by simulating the introduction of controls in the current
and expected future stock of CFC and halon equipment. These controls may
include chemical substitutes, product substitutes, and process changes (e.g.,
recycling).
The framework identifies these cost and energy impacts by undertaking
the following steps for each CFC- and halon-consuming end use:
• estimating CFC/halon use, energy use, and life-cycle costs in
baseline (i.e , uncontrolled) equipment;
specifying the impact that individual controls 1 such as a chemical
substitute, may have on CFC/halon use, energy use, and costs in
the equipment;
• defining alternative groups of controls, referred to as “control
plans,” for each equipment type that may be implemented over tim
to meet regulatory restrictions on CFCs and halons;
• . selecting a least cos.t control plan for each equipment type that
may be adopted in response to a phase out;
• sumtnRrizing total costs and reductions for the U.S. associated
with the implementation of these control plans;. and
• estimating emissions of chemical substitutes and changes in energy
use for the selected control plans.
End uses included in the analysis were:
• aerosols;
• foam insulation;
• commercial refrigeration;
• residential refrigeration;
• mobile air conditioners;
• solvent cleaning;
• sterilization; and
• halon fire extinguishers.
In Appendix A, more detailed tables showing the available control options for
each end use are presented, along with the percentage use reductions achieved
in the year 2000 by various general strategies (e.g. recycling).
“ It is also assumed that industry complies with the Montreal Protocol
prior to the year 2000. This Protocol mandates a production freeze of CFCs at
1986 levels in 1989; a 20 percent reduction of CFCs from 1986 levels in 1993,
and a 50 percent reduction of CFCs from 1986 levels in 1998. Halon production
must be frozen at 1986 levels beginning in 1992.
4
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Total costs, emission reductions, substitute use, and changes in energy
use were calculated by summing across all end uses for each year.
To translate this data into estimates of the cost of a CFC phaseout per
unit of equivalent carbon dioxide reduction, the following methodology was
used:
(1) the total cost of a CFC and halon phaseout in any given year was
- obtained. The cost included operating and maintenance expenses
for the given year as well as an annualized capital cost (6’ real
COtint ilü ) The capital cost reflects the capital outlays in
the given year as well as annualized capital costs from previous
years if appropriate;
(2) the total CFC and halon emission reductions were obtained by
compound and weighted by their respective global warming
potentials (GWPs). CFC and halon reduction on a CWP basis were
then summed to give the total reduction in carbon dioxide
equivalent emissions resulting from a CFCphaseout;
(3) the total increase in emissions of substitute chemicals were
obtained by compound and weighted by their CWP. Increased
substitute emissions on a CWP basis were then summed across all.
substitute compounds;
(4) the total change in energy use was obtained and then translated
into changes in trace gas emissions. Energy trace gas emissions
were then weighted by their CWP, and summed to give a total
decrease in carbon dioxide equivalent emissions resulting from the
reduced energy use under a CFC phaseout.
All C0 2 -equivalent emission data were then converted to equivalent emissions
of carbon.
The cost of a CFC phaseout per unit of carbon dioxide equivalent carbon
for any given year was then calculated using the following’formula:
Cost of Phaseout
CFC reductions - substitute emissions + trace gas reductions
where all gas emissions are on a carbon-equivalent GWP basis, and the CFC
reductions represent either use reductions (method 1) or emission reductions
(method 2) for the given year.
5
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3. RESULTS STThIXARY
a. Emission Reductions
Exhibit II summarizes the changes in use (method 1) or emissions (method
2) of CFCs resulting in the year 2000 from a phaseout beginning in 1989.
Accompanying changes in emissions of substitutes and energy-related trace
gases are also presented. All use/emission numbers have been adjusted by the
global warming potential factors, are aggregated across compounds and are
expressed on a carbon equivalent basis.
The results show that the vast majority of emission reduction comes from
the CFCs. The increase in emissions from the HCFC substitutes is less than 8
percent of the CFC reductions. The emission reductions due to changes in
energy-related trace gases are essentially negligible by comparison.
b. CYC Phaseout Costs
The costs of a CFC phaseout are presented in Exhibit III. The estimates
show, for example, that for the year 2000 the cost of a CFC phaseout is about
$1.3 Billion. Expressed in terms of a cost per metric ton of reduction of C02
equivalent emission (carbon basis) the cost in 2000 of a CFC phaseout is about
$2.40 per metric ton of carbon (see Exhibit IV).
The energy savings from more energy-efficient substitutes reduces the
phaseout costs by about 10 percent in the year 2000 and by about 2 percent in
the year 2010.
6
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EXHIBIT II. Greenhouse Gas Emission Reductions Resulting from a CFC Phaseout
(Unit — Millions of Kg, C0 2 -Equivalent Carbon Emissions)
Method 1. Assume Emissions — Use
Year 2000 Year 2010
CFC and Halon Reductions 881,434 967,728
Substitute Emissions 3 (43,967) (57,419)
Trace Gas Emissions 631 676
Total Reduction 838,098 910,985
Method 2. Actual Emission Reductions
Year 2000 Year 2010
CFC and Halon Reductions 588,935 957,676
Substitute Emissions (43,967) (57,419)
Trace Gas Emissions 631 676
Total Reduction 545,599 900,933
A positive change occurs in substitute emissions, so they.are
subtracted from the CFC reductions.
7
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E IBIT III.
CPC Phaseout Costs
(Unit:. Millions of
1988 Dollars)
:
Year 2000
Year 2010
Cost Without Energy
Impact
$1,456
$1,668
Energy Savings
($144)
($33)
Net Cost including
Energy Impact
$1,312
$1,635
8
-------
IBIT IV. CFC Phaseout Costs per Netric Ton of Carbon Emission Reduction
(Unit: 1988 Dollars per metric ton of C02-equivalent reduction of carbon
emitted.)
Year 2000 Year 2010
Method 1. Use — Emission
Cost Without Energy Impact $1.74 $1.83
Energy Savings ($0.17) ($0.04)
Net Cost Including Energy Impact’ $1.57 $1.79
Method 2. Actual Emission
Cost Without Energy Impact $2.67 $1.85
Energy Savings ($0.26) ($0.04)
Net Cost Including Energy Impact $2.40 $1.81
6 Totals may not add exactly due to rounding.
9
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APPENDIX A
S rrINGS FOR CONTROL PLANS AND CONTROLS SELECTED
FOR THE PEA.SEOVT S .i 1 IZ 1 SCENARIO
Start
Penetration
Percent
Market
Applied to New
and/or Existing
End Use/Control Date
us
Penetration
E iipoent
Mobile Air Conditioning
Recovery at Service (Large Shops) 1989 2 100 Existing
Recovery at Service (Medita Shops) 1990 2 100 ExIsting
Recovery at Service (SostI Shops) 1990 3 100 Existing
Oiatlty Engineering 1990 3 100 Existing
NFC1341 1992 3 100 New
H ise otd Refrigerators
Ternary Blend 1993 1 100 Mew
%arge Reójction 1989 2 50 News
Other Refrigerated App$ i ences .
Ternary BLend 1993 2 100 New
Alternate Leak Test 1989 2 100 New
Chillers
NC C-1 1992 2 100 New
HCTC-124 1996 2 100 Mew
HFC-134. 0 1992 2 100 New
Ternary Blend 1993 2 100 Mew/Existing
Recovery at Service, Leak Detection, and DisposaL 1989 2 95 New/Existing
Cold Storage
Ania 1989 3-4 40-50 New
Ternary Blend 1993 2 60 Mew
HC?C-22 2 Stage Systos 1989 3 50 Mew
Recovery at Service, Leak Detection, and Disposal 1989 2 100 New/Existing
HCFC-22 1989 2 100 New
HCFC-22 2 Stage System 1992 2 100 Mew
Recovery et Service, Leak Detection, & DisposaL 1989 2 95 New/Existing
Process Refrigeration
1989 2-3 20-30 Mew
Ternary Blend 1995 2 70 New
HCPC-22 2 Stage System 1989 2 70-80 Mew
Recovery at Service, Leak Detection, and DisposaL 1989 2 100 New/Existing
Refrigerated Transoort
Ternary Blend 1993 2 100 New
HCFC-125 1994 2 100 New
Solvents
Terperies and Aqueous Cleaning 1990 5 25 New
No CLean 1990 5 50 New
• HCFC141b/HCFC123 1991 2 25 New
NCFC-141b/HCFC-123 Retrofit 1991 5 100 Existing
Retain Waste Solvent 1989 1 100 Existing
Housekeeping Controls 1989 1 100 Existing
CFC-113 Cover (Open-Tap) 1989 1 100 Existing
CFC-113 Hoist (Open Top) 1989 1 100 Existing
Refrigerated Freeboard ChiLler (Open-Top) 1989 1 50 Existing
Carbon A erption and Drying Tuv eL 1989 1 50 Existing
-------
APPENDIX A (CONT.)
SETTINGS FOR CONTROL PLANS AND CONTROLS SELECTED
FOR PEASEOUT S i ULE 1 SCENARIO
Start
Penetration
Percent
Market
A t ad to New
and/or Existing
End Uss/C ritro& Oats
T1
Penetration
E JifI a e nt
Sterilization
HC C BLend 1992 5 100 New/ExIsting
Nitrogen Purge then Pure Ethylene Oxide 1989 5-7 40-50 Existing
Contract it 1989 3-5 15 ExIsting
Dlsposabt.s 1959 3 20 Existing
Ste a m CLeaning 1989 1 25 New
Ethylene Oxide/Carbon DIoxide 1989 3-5 25 ExistIng
R1 Id Foam !nsutation
KCFC123/HCFC141b 1993 2 100 New
F(exibte Foam -- Molded
water 8Lose Syst 1959 3 80 New
MCIC/141b/HCFC1Z3 1993 2 20 New
Flexible Foam -- Stabstock
Water BLosmI Syst 1959 4 70 New
Pro .act S*. t1tutes 1959 4 20 New
HC C-141b/NCFC-125 1993 2 10 New-
peckaginq Fom,
4CFC -22 1959 1-3 33-40 New
water BImim 1959 3 80 New
Nyd r ocartM .a 1989 1-3 20-33 New
HCFC-142b 1959 1-3 33 New
HC,C-124 1993 2 50 New
NCIC141b/123 1993 2 20 New
Aerosols
Carbon Dioxide 1988 4 50 Hew
HCFC22 BL 1955 2 50 New
i-1301 Total Ftoodinq Syote i (Eteetronics
Sprinkl.rs with Early Warning Detection, 1993 7 100 New
Fire Separation, Re xed Cr1 urtibfLtty
Cables, Co-Cabinet and Si.Cftoor
Increased Training 1959 2 100 Existing
Manual Activation 1989 2 100 Existing
Contained DIscharge 1989 2 100 New
Increased Recovery 1989 2 100 Existing
Decreased Fre .iency of Teardowi 1989 2 100 Exi sting
H-1301 Total Ftoodinq (AU Other Apolications )
Total FLooaing Carbon Dioxide 1959 , 3-7 100 Mew
Increased Training 1989 2 100 Existing
Manual Activation 1989 2 100 Existing
COntained Discharge 1989 2 100 Mew
Increased Recovery . . 1989 2 100 Existing
Decreased Fre jency of Teardoici 1989 2 100 Existing
1993
11
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APPENDIX A (CONT )
SETTINGS FOR CONTROL PLANS AND CONTROLS SELECTED
FOR PEAsEOu’r S D LE L SCENARIO
Start
Penetration
Percent
Market
Applied
and/or
tO New
Existing
End Use/Control Date
T i
Penetration
E &Ij iu. nt
14-1211 Portable Extin uisheri (EtectroflieS
Carbon Dioxide 1989 10 100 New
Increased Training (Va) 1989 2 100 ExIsting
Contained Discharge 1989 2 100 Mew
Increased Recovery 1989 2 100 ExIsting
Decreased Fre jeney of Teardoie 1989 2 100 ExistIng
14 —1211 Portable xt1nquisher (F( . ble.
Reiidential and General Uses )
Dry CI eaical 1989 7-10 100 Mew
Increased Training (VCR) 1989 2 100 Existing
Contained Discharge 1989 2 100 Mew
Increased Recovery 1989 2 100 ExIsting
Decreased Froqus y of Tserdoiai 1989 2 100 Existing
1993
Portable 44-1211 and 1301 x inqui her
( Nit i arv/Gve .. - .t1
Dry Cheaical 1993 7 100 New
Carbon Dioxide 1993 7 100 Mew
Increased Training (YCS) 1989 2 100 ExIsting
Contained Discharge 1989 2 100 New
Increased Recovery 1989 2 100 Existing
Decreased Fre jsncy of Te.rdow 1989 2 100 ExistIng
12
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APPENDIX A (CONT.)
PERCENTAGE CPC USE REDUCTIONS BY VARIOUS STRATEGIES IN THE YEAR 2000
Strate v Percent Reduction
1. Recycling of CFCs 21%
2. CFC Pool Use 8%
3. Chemical Substitute 55%
4. Process Substitute 16%
13
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ATTACHMENT H
CO 2 Reduction Cost
06W0658C
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INCREMENTAL COST OF CARBON EQUIVALENT OF EMISSIONS AVOIDED:
(S/metric ton)
YEAR 2000 Cuiulat lve
[ mis avoided [ mis avoided Total Net Cost Unit Cost
Control Strategy (mit. m.t./yr) (mit. m.t./yr) (me 1988$/yr) (S/met. ton)
TRANSPORTATION LDV - STEP 1 3.2 3.2 -1,767 -$546.47
RESIDENTIAL FUEL SUBSTITUTION - STEP 1 2.8 6.0 -1,372 -$492.82
TRANSPORTATION LOT STEP 1 3.7 9.7 -1,766. -$476.88
COMMERCIAL FUEL SUBSTITUTION - STEP 2 2.4 12.2 -805 -$330.46
TRANSPORTATION IDT - STEP 2 15.5 27.7 -4 .756 -$306.40
TRANSPORTATION LDV - STEP 2 29.1 56.8 -7,659 -$263.43
RESIDENTIALSHELL RETROFIT - ELECTRIC 37.6 94.3 -7,281 -$193.83
RESIDENTIAL ELECTRIC APPLIANCES 34.4 128.8 -6,092 -$176.87
AIR TRANSPORTATION 0.8 129.6 -131 -$156.94
TRANSPORTATION LDT - STEP 3 9.6 139.2 -1,489 4155.53
COMMER1CAL ELECTRIC CONSERVATION STEP 1 37.8 177.0 4,329 -$114.48
TRANSPORTATION LDV - STEP 3 6.5 183.4 -604 -$93.41
RESIDENTIAL FUEL SUBSTITUTION - STEP 2 2.8 186.2 -252 -$90.52
ELECTRIC UTILITY HYDRO - STEP 1 8.7 194.9 -522 -$60.29
INDUSTRIAL COGENERATION - STEP 1 13.0 207.9 -705 -$54.22
COMMERCIAL FUEL SUBSTITUTION - STEP 1 0.9 208.8 -39 -$43.10
COMNERICAL ELECTRIC CONSERVATION STEP 2 10.2 219.0 -342 -$33.61
RESIDENTIAL GAS APPLIANCES - STEP 1 6.6 225.6 -178 -$26.99
ELECTRIC UTILITY WIND STEP 1 5.7 231.3 -134 -$23.48
Landfill Gas Recovery 13.5 244.7 -305 -$22.66
Coal Bed Methane Recovery 23.5 268.3 0 50.00
CFC Phaseout 545.6 813.9 1,312 $2.40
Methane from Animal Wastes 2.3 816.2 ii $2.97
Reforest Low Cost Lands 9.3 825.4 240 525.92
INDUSTRIAL FUEL SUBSTITUTION - STEP 2 1.7 827.2 50 $28.74
COMMERICAL ELECTRIC CONSERVATION STEP 3 20.4 847.6 1,054 $51.58
Reforest High Cost Lands 9.0 856.6 483 $53.58
TRANSPORTATION LOT - STEP 4 0.2 856.8 21 $99.95
TRANSPORTATION LDV - STEP 4 5.1 861.9 526 $104.16
INDUSTRIAL MEAT PUMPS 8.9 870.8 1,470 5164.23
INDUSTRIAL COGENERATION - STEP 2 10.4 881.2 1,709 $164.25
INDUSTRIAL FUEL SUBSTITUTION - STEP 1 4.4 885.7 828 $186.54
ELECTRIC UTILITY FUEL SUBSTITUTION - STEP 1 43.2 928.8 8,050 $186.54
ELECTRIC UTILITY FUEL SUBSTITUTION - STEP 2 24.7 953.5 5,200 $210.87
INDUSTRIAL ELECTRIC MOTORS 14.0 967.5 7,858 $561.07
RESIDENTIAL SHELL RETROFIT - GAS 20.3 987.8 13,025 $642.91
INDUSTRIAL COGENERATION - STEP 3 1.5 989.3 1,150 $745.99
RESIDENTIAL GAS APPLIANCES - STEP 2 3.2 992.4 4,077 $1,294.12
INDUSTRIAL COGENERATION - STEP 4 3.9 996.3 7,734 $1,984.46
996.3 996.3 14,267
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INCREMENTAL COST OF CARBON EQUIVALENT OF EMISSIONS AVOWED:
(S/metric ton)
YEAR 2010 Ctzmjtative
[ mis avoided [ mis avoided Totat Met Cost Unit Cost
ControL Strategy (mit. m.t.Iyr) (mit. m.t./yr) (an 1988$/yr) (S/met, ton)
TRANSPORTATION LDT - STEP 1 3.7 3.7 -2,669 -$712.28
RESIDENTIAL FUEL SUBSTITUTION - STEP.1 2.8 6.5 -1,736 -$623.56
TRANSPORTATION LDV - STEP 1 5.1 11.6 -3,157 -1622.14
COMMERCIAL FUEL SUBSTITUTION - STEP 2 2.6 14.2 -1,231 -$465.44
TRANSPORTATION LOT - STEP 2 35.3 49.5 -16,348 -$463.33
TRANSPORTATION LDV - STEP 2 57.0 106.6 -25,228 -$442.32
TRANSPORTATION LOT - STEP 3 19.9 126.5 -7,144 -1359.18
TRANSPORTATION LDV - STEP 3 13.2 139.6 -4,257 -$322.75
TRANSPORTATION LOT - STEP 4 0.4 140.1 .115 -1283.51
AIR TRANSPORTATION 2.0 142.1 -503 -$247.08
RESIOENTIALSHELL RETROFIT - ELECTRIC 33.7 175.8 -7,480 -$222.10
RESIDENTIAL FUEL SUBSTITUTION - STEP 2 2.8 178.6 -616 -$221.26
TRANSPORTATION tOy - STEP 4 8.3. . 186.8 -1,610 -$194.30
RESIDENTIAL ELECTRIC APPLIANCES 44.2 231.1 -8,020 -1181.26
COMMERICAL ELECTRIC CONSERVATION STEP 1 45.7 276.8 -6,081 -$133.04
TRANSPORTATION ETHANOL SUBSTITUTION 19.1 295.9 -2,527 -$132.18
ELECTRIC UTILITY SOLAR - STEP 1 19.1 315.0 -2,527 -$132.18
ELECTRIC UTILITY HYDRO - STEP 1 . 17.3 332.3 -1,464 -$84.54
RESIDENTIAL GAS APPLIANCES - STEP 1 4.9 337.3 -342 -$69.20
ELECTRIC UTILITY GEOTHERMAL 14.2 351.5 -799 -$56.14
COMMERICAL ELECTRIC CONSERVATION STEP 2 12.5 364.1 -657 -$52.37
COMMERCIAL FUEL SUBSTITUTION - STEP 1 0.7 364.8 -20 -$28.74
INDUSTRIAL COGENERATION - STEP 1 13.0 377.8 -338 -$26.01
LandfiLL Gas Recovery 26.9 . 404.7 -610 -$22.66
Coat Bed Methane Recovery 30.7 435.4 0 $0.00
CFC Phaseout 900.9 1336.3 1,635 $1.81
Methane from Animal Wastes 4.6 1340.9 14 $2.97
Reforest Low Cost Lands 44.1 1385.0 412 $9.35
Reforest High Cost Lands 43.0 1427.9 802 $18.67
ELECTRIC UTILITY WIND - STEP 1 11.4 1439.3 357 $31.35
COMMERICAL ELECTRIC CONSERVATION STEP 3 25.2 1464.5 837 $33.21
INDUSTRIAL FUEL SUBSTITUTION - ST P 2 1.7 1466.3 75 $43.10
ELECTRIC UTILITY BIOMASS 14.2 1480.5 764 $53.68
ELECTRIC UTILITY NUCLEAR . 28.4 1508.9 2,247 $78.98
INDUSTRIAL HEAT PUMPS 8.9 1517.9 1,334 $149.10
ELECTRIC UTILITY HYDRO - STEP 2 8.7 1526.6 1,573 $181.68
INDUSTRIAL COGENERATION - STEP 2 10.4 1537.0 2,012 $193.35
ELECTRIC UTILITY FUEL SUBSTITUTION - STEP 1 79.9 1616.8 18,301 $229.14
INDUSTRIAL FUEL. SUBSTITUTION - STEP 1 4.4 . 1621.3 1,188 $267.64
ELECTRIC UTILITY FUEL SUBSTITUTION - STEP 2 24.7 1645.9 7,200 $291.97
ELECTRIC UTILITY SOLAR - STEP 2 5.7 1651.6 2,761 $485.33
ELECTRIC UTILITY WIND - STEP 2 5.7 1657.3 2,841 $499.39
INDUSTRIAL ELECTRIC MOTORS 19.1 1676.4 10362 $542.54
RESIDENTIAL SHELL RETROFIT - GAS 29.5 1705.9 19,013 $644.98
INDUSTRIAL COGENERATION - STEP 3 1.5 1707.4 1,195 $775.41
RESIDENTIAL GAS APPLIANCES - STEP 2 3.4 1710.8 3,176 $947.40
ELECTRIC UTILITY IGCC 2.7 1713.5 4,716 $1,761.02
INDUSTRIAL COGENERATION - STEP 4 3.9 1717.3 7,842. $2,012.36
1717.3 1717.3 -4,821
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ATTACHMENT I
Renewable Energy Background
Information
06W0658C
-------
The enclosed back-up documentation was provided by Solar Energy Research Institute
(SERI) at ICFs request. The tables present additional detail on the SERI market penetration
estimates contained in their September 29, 1989 interlaboratory analytic paper. Also, presented is
an ICF compilation of certain key assumptions (e.g., capital costs, O&M costs) underlying the SERI
analysis of September 1989. Note that SERI’s final report, “The Potential of Renewable Energy: An
Interlaboratory White Paper”, was issued in March 1990, and may reflect some revisions relative to
the September 1989 paper that ICP utilized.
-------
liui n
US. RENEWA6LE ENERGY TECHNOLOGY ASSESSMENt -. TABLE I
RESOLEE AREA OF LAND TECHNOLOGY p c
TECHNOLOGY REQUIREMENtS REQUIRED per P4 STATUS. DUTY CYCLE APPLICATIONS DISPATCHIBILITy
BIO$4ASS 50-10 TONS/DAY 0.16 - 0.25 C0*(RCIAL BASE CENTRAL STATION!
FOR I HU DISTRIBUTED
GEOTHERMAL SATLN 1ATED STEAM 0.1 - 0.4 COIO4ERCIAL BASE CENTRAL STATION! YES
350 F DISTRIBUTED
HYDROPOWER WATER ELEVATION NA. COII4ERCIAL PEALING! CENTRAL STATION! YES
10 - 1004 Ft INTERMEDIATE DISTRIBuTED
PHOTOVOLTAIC SOLAR INSOLATION 10 - 20 EARLY PEALING! INTERCONNECTED ( NO
4-6 kWh/m(2)/day COMMERCIAL INTERMEDIATE CENTRAL STATION
SOLAR THERMAL SOLAR INSOLATION 4.33 - IS DEICNSTRATIO4i I PEALING CENTRAL STATION! NO
6 kWh/m(2 )/day EARLY COMMERCIAL DISTRIBUTED
WIND AVERAGE WIND 10 - 40 COMMERCIAL PEALING! CENTRAL STATION! NO
SPEEDS ‘ 12 mph INTERMEDIATE DISIRIBIJIED
U.S. RENEWABLE ENERGY TECHNOLOGY ASSESSMENT •- tABLE 2
AVERAGE SIZE (M V) LIFETIME (yrs) AVAILABILITY (N) CAPACITY FACTOR (N) lEAD TIME (yr.) CAPITAL £051 ( 8/ k w) DIN COSTS (allis/kwh) (EVELIZED COST (cent./kUI)
TECHNOLOGY 1985 2000 1985 2000 1985 2000 1985 2000 1985 2000 198$ 2000 1985 2000 1985 2000
BIO#4ASS 1-10 1-10 20-30 20-30 1990 80-90 508O 23 23 11005320 1500-5820 3-12 1.1 1 3.8-11.6 4.0-12.5
GEOTHERMAL 1-110 5-lID 30 30 90-95 95 10-90 15-95 1.5-3.5 1.5-3 930-2213 1200-2000 5-15 10-20 5.5-6.8 4-6
HYDROPOWER 1-31+ 1-31+ 50-15 50-15 90-95 92-91 IS-SO NA. 2-5 2-1 900-4000 592-4000 2-6 3-B 1.5-4.2 1-29
PHOTOVOLTAIC .001-4.5 5-10 20-30 30 80-98 90-99 15-35 20-35 0.5-2 0.5-2 1000-11000 1560-3250 5-ID 3-10 25-125 6-30.
SOLAR THERMAL .01-10 .05-100 20-30 20-30 88-92 90-95 5-30 20-60 1-5 I-S 3000-4151 1550-3000 N.A. 6-Il 13-IS 4-6
WIND . 1-I .3-3.2 10-30 20-40 16-98 94-99 3-31 10-40 0.5-3 0.5-2 1000-4000 900-1300 5-44 5-12 4-29 3.5-9
-------
HYDRO
GEOTHERMAL
SQL THERMAL
PHOTOVOLTAIC
WIND
3I OMASS
3.14
0.22
0.01
0.00
0.03
0.42
DRAFT 1/10/90
BUSINESS AS USUAL CASE
3.40
0.37
0.04
0.01
0.15
0.95
3.44
0.59
0.18
0.10
0.94
1.64
3.46
0.85
0.52
0.49
1.71
1.93
HYDRO
C EOTHEP.MAL.
SQL THERMAL
PHOTOVOLTAI C
WIND
BIOMASS
299,047,619
20,952,381
619,048
57,143
2,761,905
40,000,000
323,809,524
35,238,095
3,809,524
952,381
14,285,714
90,476,190
327,619,048
56, 190 , 476
17,142,857
9,523,810
89,523,810
156,190,476
329,523,810
80,952,381
49,523,810
46,666,667
162,857,143
183,809,524
HYDRO
GEOTHERMAL
SQL THERMAL
PHOTOVOLTAIC
WIND
BIOMASS
85,345
2,814
214
26
1,433
5,708
POWER (MW)
92,411
4,732
1,318
435
7,413
12,910
93,499
7,546
5,930
4,349
46,453
22,287
94,042
10,872
17,132
21,309
84,505
26,229
I % .
11
: ;I - i 1
L .)UU .t U ,
RENEWABLE ELECTRIC ENERGY MARKET PROJECTIONS
ENERGY (QUADS)
1.988 2000 2010 2020
1.988 2000 2010 . 2020
ENERGY (MWh)
1988
2000 201.0 2020
Assuming 1 kWh 10,500 BTU
-------
RENEWABLE ELECTRIC MARKET PROJECTIONS
IJUSINESS AS USUAL SCENARIO
100
90
80
70
60
40
30
20
10
0
1988
+ GEO
0 SW
YEAR
PV
>: WNI)
V IJI O
U)
4’
4 )
L)
0
50
2000 0I0
9 A’)
0 IIYE)
-------
RENEWABLE ELECTRIC ENERGY MARXET PROJECTIONS
DRAFT 1/10/90
NATIONAL PREMIUMS CASE
ENERGY (QUADS)
HYDRO
GEOTHERMAL
SOL THERMAL
PHOTOVOLTAIC
WIND
BIOMASS
3.1.4
0.22
0.01
0.00
0.03
0.42
3.49
0.49
0.08
0.02
0.29
1.51
4.15
0.79
0.35
0.25
1.86
2.1
4.9
1.01
0.52
0.49
2.06
2.39
HYDRO
GEOTHERMAL
SOL THERMAL
PHOTOVOLTAIC
WIND
BIOMASS
299,, 047,61.9
20,952,381
619,048
57,143
2, 7619 905
40,000,00G
332,380,952
46,666,667
7,619,048
1,904,762
27,619,048
143,809,524
395,238,095
75,238,095
33,333,333
23,809,524
177,142,857
200,000,000
466,666,667
96,190,476
49,523,810
46,666,667
196,190,476
227,619,048
HYDRO
GEOTHERMAL
SOL THERMAL
PHOTO VOLTAIC
WIND
BIOMASS
85,345
2,814
214
26
1,433
5,708
94,858
6,267
2,636
870
14,331
20,521
112,796
10,104
11,531
10,872
91,917
28,539
133, 181
12,918
17,132
21,309
101,801
32,480
— -
1988
2010
2000
2000
1988
2020
202Q
ENERGY (MWh)
2010
1988
POWER (MW)
2000
2010
2020
-------
RENEWABLE ELECTRIC MARKET PROJECTIONS ’
NATIONAL PREMIUMS CASE
140
130
120
110
(0
4- )
100
S
t E l
a )
( 0
80
70
4:
t1lL
C ) 50
14
40
0
30
20
10
0
1988 2020
2000 2010
[ I I IY I) t CEO
SOt. 1 W
X Will) V 1 110
-------
HYDRO
GEOTHERMAL
SOL THERMAL
PHOTO VOLTA IC
WIND
BIOMASS
3.14
0.22
0.0].
0.00
0.03
0.42
DRAFT 1/10/90
3.97
0.51
0.13
005
0.24
1.14
5.03
1.03
0.54
0.49
1.81
1.91
5.98
2.37
1.18
1.58
3.02
2.39
HYDRO
G EOTHERMAL
SQL THERMAL
PHOTOVOLTAIC
WI ND
BIOMASS
299,047 ,619
20,952,381
619,048
57,143
2,761,905
40,000,000
378,095,238
48,571,429
12,380,952
4,761,905
22,857,143
108,571,429
479,047,619
98,095,238
51,428,571
• 46 , 666, 667
172,380,952
181,904,762
569,523,810
225,714,286
112,380,952
150,476,190
287,619,048
227 ,619,048
1988
2000
POWER (MW)
2010
2020
HYDRO
GEOTHERMAL
SQL THERMAL
PHOTO VOLTAI C
WIND
BIOMASS
85,345
2,814
214
26
1,433
.5, 708
107,904
6,523
4,283
2,174
11,860
15,492
136,715
13,174
17,790
21,309
89,446
25,957
162,535
30,313
38,875
68,711
149,242
32,480
RENEWABLE ELECTRIC ENERGY MARXET PROJECTIONS
R&D INTENSIFICATION CASE
ENERGY (QUADS)
1988
2000
2010
2020
ENERGY
(t Wh)
1988
2000
•
2010
2020
-------
RENEWABLE ELECTRIC MARKET PROJECTIONS
R&D INTENSIFICATION CASE
170
160
150,
140
130
4 - I
120
110
100
90
1 -4 (0
80
0
60
• 50
0
40
30
20
10
0
1988 202()
\‘EAR
2000 2010
0 HYI) + GEO
S0.L £ • PV
WN I) lilO
-------
CAPACITY FACTOR TABLE
HYDRO 40.0%
GEOThERMAL 85.0%
SQL THERMAL 33.0%
PHOTOVOLTAICS 25.0%
WIND 22.0%
BI OMASS 80.0%
------- |