Greenhouse Gas Reduction Strategies in Utah:
An Economic and Policy Analysis
Prepared for:
The U.S. Environmental Protection Agency
Prepared by:
The Utah Department of Natural Resources
Office of Energy and Resource Planning
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Table of Contents
Executive Summary ES-1
I. Background ES-1
Table 1. Fossil Fuel GHG Emissions Baseline in Tons C02, 1990-2010 ES-1
II. Major Findings ES-1
A. Baseline ES-1
Figure 1. Fossil Fuel GHG Emissions Baseline 1990-2010 ES-2
B. Mitigation Strategies ES-2
Table 2. GHG Cost and Reduction - Summary by Sector ES-3
Table 3. Fossil Fuel Mitigation Strategies Ranked By Feasible $/ton ES-3
Figure 2. Cost vs. Reduction - Feasible ES-4
Figure 3. Cost vs. Reduction - Potential ES-5
C. Economic Impact ES-6
Table 4. Estimated Average Annual Changes in Earnings and Employment ES-6
Part One: Introduction 1-1
I. Background 1-1
II. Scope of Research 1-2
III. Methodology 1-2
IV. Report Structure 1-4
Part Two: The Greenhouse Effect and Global Initiatives 2-1
I. Background and State of the Science 2-1
A. Climate and Weather in Context: A History of Climate Change 2-1
Figure 2-1. Northern Hemisphere Temperature 1400 - 1995 2-2
Figure 2-2. Northern Hemisphere temperature , 1902 - 1995 2-3
B. The Science of the Greenhouse Effect 2-3
II. International Treaties 2-4
A. Framework Convention on Climate Change 2-4
B. Kyoto Protocol 2-4
IE. The International Science Community 2-6
Part Three: Utah Greenhouse Gas Emissions Inventory and Mitigation Strategies .... 3-1
I. Phase I: The Utah Greenhouse Gas Inventory 3-1
A. Carbon Dioxide 3-1
B. Methane 3-2
C. Nitrous Oxide 3-2
D. Utah Forests 3-2
II. Goal of the Utah Greenhouse Gas Mitigation Plan 3-3
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III. Criteria for Selection of Mitigation Strategies 3-3
IV. Part Four: Utah Energy Baseline 4-1
I. Overview of Utah Total Energy Use and GHG 4-1
A. Utah Energy Use by Fuel and Sector 4-1
Table 4-1. Carbon Content of Fossil Fuels 4-1
B. Methodology 4-1
Table 4-2. Utah C02 Emissions by Energy Source,
Excluding Elec. Exports ($) 4-2
Table 4-3. Utah C02 Emissions by Energy Source,
Excluding Elec. Exports (%) 4-2
Table 4-4. Average Annual Growth Rate in C02 Emissions,
by Energy Source 4-3
Table 4-5. Utah C02 Emissions
by Energy Source and End-Use Sector in 1998 4-3
Table 4-6. Utah C02 Emissions
by Energy Source and End-Use Sector in 1998 4-3
Table 4-7. Utah Residential Electricity Use 4-4
C. The Matrix of Total Energy Use and C02 Emissions 4-4
Utah Population Growth 4-4
II. The Utah Residential Sector and Carbon Dioxide Emissions 4-5
A. Overview of Aggregate Trends 4-5
Table 4-8. Utah Residential Natural Gas Use 4-5
B. Baseline Carbon Dioxide Emissions in the 1990s 4-6
Table 4-9. Utah Residential C02 Emissions 4-6
Table 4-10. Utah Residential C02 Emissions as a percent 4-6
Table 4-11. Annual Growth in Utah Residential C02 Emissions 4-6
C. The Matrix of Residential Sector Energy by End Use 4-7
Table 4-12. Utah Residential C02 Emissions in 1998 4-7
Table 4-13. Utah Residential C02 Emissions in 1998 as a percent 4-7
III. Utah Commercial Sector Energy Use and Carbon Dioxide Emissions 4-8
A. Overview of Aggregate Trends 4-8
Table 4-14. Utah Commercial Electricity Use 4-8
Table 4-15. Utah Commercial Natural Gas Use 4-8
Table 4-16. Utah Commercial C02 Emissions 4-9
Table 4-17. Utah Commercial C02 Emissions as a percent 4-9
B. Baseline Utah Commercial Sector Carbon Dioxide Emissions in the 1990s . 4-9
Table 4-18. Annual Growth in Utah C02 Emissions 4-9
Table 4-19. Utah Commercial C02 Emissions in 1998 4-9
Table 4-20. Utah Commercial C02 Emissions in 1998 as a percent 4-10
The Utah Commercial Sector and Tourism 4-10
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C. The Matrix of Commercial Energy Use and Carbon Dioxide Emissions ... 4-11
IV. The Utah Industrial Sector and C02 Emissions 4-11
A. Overview of Aggregate Trends 4-11
Table 4-21. Utah Industrial Energy Use 4-11
B. Baseline Utah Industrial Sector C02 Emissions in the 1990s 4-11
Table 4-22. Utah Industrial C02 Emissions 4-12
Table 4-23. Utah Industrial C02 Emission as a percent 4-12
Table 4-24. Annual Growth in Utah Industrial C02 Emissions 4-12
Table 4-25. Utah Industrial C02 Emissions in 1998 4-13
C. The Matrix of Industrial Energy Use and C02 Emissions 4-13
V. The Utah Transportation Sector and C02 Emissions 4-13
A. Overview of Aggregate Trends 4-13
Table 4-26. Utah Industrial C02 Emissions in 1998 as a percent 4-14
B. Baseline Utah Transportation C02 Emissions in the 1990s 4-14
Table 4-27. Utah Gasoline Consumption 4-14
Table 4-28. Utah Automobiles and Miles Traveled 4-14
1-15 Reconstruction 4-15
Table 4-29. Utah Transportation C02 Emissions 4-15
Table 4-30. Utah Transportation C02 Emissions as a percent 4-16
Table 4-31. Annual Growth in Utah Transportation C02 Emissions 4-16
C. The Matrix of Transportation Energy Use and C02 Emissions 4-16
Table 4-32. Utah Transportation C02 Emissions in 1998 4-16
Table 4-33. Utah Transportation C02 Emissions in 1998 as a percent 4-17
VI. Utah Electric Utility Sector and C02 Emissions 4-17
A. Overview of Aggregate Trends 4-17
B. Baseline Utah Electric Utility Sector C02 Emissions in the 1990s 4-18
C. Electric Utility Energy Use and C02 Emissions 4-18
Table 4-34. Electric Utility Fuel Consumption 4-18
Table 4-35. Utah Coal-fired Power Plant Capacity 4-18
Table 4-36. Utah Electric Utility C02 Emissions 4-19
Table 4-37. Utah Electric Utility C02 Emissions as a percent 4-19
Table 4-38. Annual Growth in Utah Electric Utility C02 Emissions 4-19
Deregulation 4-20
VII. Assessment of Potential Energy Savings 4-20
Residential Sector 4-20
Commercial Sector 4-21
Industrial Sector 4-21
Transportation Sector 4-21
Electric Utility Sector 4-21
The Non-Fossil Sector 4-21
Land-Use Planning 4-22
Deregulation and Greenhouse Gas Emissions 4-22
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Part Five: Fossil Fuel Mitigation Strategies
I. Overview 5-1
II. Residential Sector 5-1
A. Introduction 5-1
B. Selected Strategies 5-2
Major Appliance Efficiency Gains 5-2
Electric Water Heater to Natural Gas Conversion 5-2
Refrigerators 5-3
Clothes Dryers 5-3
Clothes Washers 5-3
Residential Indoor Lighting 5-3
Building Code Improvements 5-4
Energy Star® Homes 5-4
Weatherization 5-5
Green Power Marketing 5-5
Net Metering 5-6
C. Residential Sector Summary 5-6
Table 5-1. Summary of Residential Sector Strategies 5-6
III. Commercial Sector 5-7
A. Introduction 5-7
B. Selected Strategies 5-7
Lighting 5-7
High-Efficiency Lighting Retrofit 5-7
Lighting Controls 5-8
Heating, Ventilation, and Air Conditioning (HVAC) 5-8
HVAC Automatic Control System 5-9
Table 5-2. Summary of Commercial Sector Strategies 5-9
Building Commissioning/Recommissioning 5-9
Variable Speed Drives 5-10
Commercial Refrigeration 5-10
Public Sector Buildings 5-10
Green Marketing 5-11
Net Metering 5-11
C. Commercial Sector Summary 5-12
The Utah Department ofNatural Resources Building 5-12
IV. Industrial Sector 5-13
A. Introduction 5-13
Table 5-3. Energy Consumption by SIC Category 5-13
B. Selected Strategies 5-14
Motors 5-14
Table 5-4. Motor System Energy Use by Major Industry Group . . 5-14
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Industrial Process 5-15
Table 5-5. Industrial Electricity Energy and Emissions Savings . . 5-15
Space Conditioning 5-16
Table 5-6. Industrial Electricity Energy and Emissions Savings . . 5-16
Process Cooling 5-16
Process Heating and Water Heating 5-17
Table 5-7. Energy Balance: CHP Versus Central Station 5-17
Table 5-8. Emissions Reduction and Costs for
Combined Heat and Power 5-18
Steam System Optimization 5-18
High-Efficiency Lighting Retrofit 5-18
C. Industrial Sector Summary 5-19
Table 5-9. Summary of Industrial Sector Strategies 5-19
V. Transportation Sector 5-20
A. Introduction 5-20
B. Selected Strategies 5-20
Optimal Tire Inflation 5-20
CAFE Standards and Feebates 5-21
Alternative Fuel Vehicles 5-21
Telecommuting 5-22
Enhanced I&M 5-23
Retire Older Vehicles 5-23
Vehicle Speed Control 5-23
Smart Traffic Lights and Highways 5-23
Mass Transit - General 5-23
Mass Transit - TRAX 5-24
Mass Transit - Doubling of UTA Bus Fleet 5-24
Mass Transit - Regional Commuter Rail 5-24
Trucking-to-Rail Substitution 5-25
Fuel Efficient Airplane Jet Engines 5-25
Table 5-10. Summary of Transportation Sector Strategies 5-25
C. Transportation Sector Summary 5-26
VI. Electric Utility Sector 5-26
A. Introduction 5-26
B. Selected Strategies 5-27
Solar (photovoltaic) 5-27
Table 5-11. Solar PV Cost and C02 Reduction 5-27
Geothermal 5-27
Table 5-12. Geothermal Cost and C02 Reduction 5-27
Hydro (pumped storage) 5-27
Table 5-13. Hydro (pumped storage) Cost and C02 Reduction . . . 5-28
Wind Power 5-28
Table 5-14. Wind Power Cost and C02 Reduction 5-28
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Distributed Resources 5-28
Table 5-15. Range of Distributed Power Technologies 5-29
Table 5-16. Simple-Cycle Combustion/Combined-Cycle
Combustion Turbine Cost and C02 Reduction 5-29
VII. Land Use Planning 5-30
A. Introduction 5-30
The Spatial Patterns of Energy Use and Emissions 5-30
Table 5-17. Influence of Urban Planning on Energy Demand .... 5-30
Table 5-18. Typical Community Energy Uses 5-31
Table 5-19. Energy Effects of Residential Density 5-31
Table 5-20. Urban Energy Use Per Household 5-32
Table 5-21. Suburban Energy Use Per Household 5-32
Table 5-22. Energy Effects of Land-use Mix 5-33
The Role of Envision Utah 5-33
The Public's Role in Envision Utah 5-33
The Envision Utah Process 5-34
Implementation 5-34
In-Depth Scenario Analysis 5-35
Scenario A 5-35
Scenario B 5-36
Scenario C 5-37
Scenario D 5-39
Part Six: Non-Fossil Greenhouse Gas Emissions
I. Industrial Sources 6-1
A. Limestone Use 6-1
Process Overview 6-1
Emissions Reduction Potential 6-1
The Utah Limestone Industry 6-2
B. Lime Production 6-2
Process Overview 6-2
Emissions Reduction Potential 6-3
Table 6-1. Lime Production Unit Operations 6-4
The Utah Lime Industry 6-4
C. Cement Production 6-4
Process Overview 6-4
Emissions Reduction Potential 6-5
Table 6-2. Cement Production Unit Operations 6-6
Utah Cement Industry 6-6
D. Soda Ash 6-7
Process Overview 6-7
Emissions Reduction Potential in Utah 6-8
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II. Energy Sources 6-9
A. Oil and Natural Gas Production Processing 6-9
Process Overview 6-9
Table 6-3. Methane From Oil and Gas Production and Transportation . 6-9
Gas Transmission and Distribution 6-9
Oil Refining and Transportation 6-10
Gas Venting 6-10
Emissions Reduction Potential 6-10
B. Coalbed Methane 6-10
Process Overview 6-10
Emissions Reduction Measures 6-11
Emissions Reduction Potential in Utah 6-11
Table 6-4. Coalbed Methane Cost and C02 Reduction 6-12
III. Agriculture Sources 6-12
A. Fertilizer 6-12
Process Overview 6-12
Emissions Reduction Strategies 6-13
Efficiency Improvements 6-13
B. Methane Emissions from Domesticated Livestock 6-14
Process Overview 6-14
Table 6-5. Domesticated Livestock Emissions 6-15
Emissions Reduction Potential 6-16
Reduction Opportunities in Utah 6-16
Table 6-6. Performance and Emission Factors
for Waste-to-Energy Proj ect 6-16
Dairy Cattle Strategies 6-17
Beef Cattle Strategies 6-17
IV. Waste Management 6-18
A. Landfill Methane 6-18
Process Overview 6-18
Emissions Reduction Potential 6-19
Table 6-7. Annualized Cost of Waste-to-Electricity Mitigation .. 6-20
Landfill Methane Recovery in Utah 6-20
B. Municipal Wastewater 6-21
Process Overview 6-21
Emissions Reduction Potential 6-21
Emissions Reduction Potential in Utah 6-22
Digester Gas 6-22
Energy Utilities 6-22
Table 6-8. Summary of Recent Power Usage 6-23
Energy Resource 6-23
Power Generation Potential 6-23
Plant Heating Needs 6-23
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Existing Combined Heat and Power Facilities 6-24
Planned Facilities 6-24
Table 6-9. Economic Comparisons of Wastewater Methane
Recovery Projects 6-24
Recommendations 6-24
Table 6-10. Municipal Landfill Costs and Reduction 6-25
Part Seven: Economic Impact of Selected Greenhouse Gas Mitigation Strategies 7-1
Table 7-1. Assessing the Effect on the Utah Economy 7-1
Table 7-2. Residential Sector Investment Assumptions 7-2
Table 7-3. Commercial Sector Investment Assumptions 7-2
The Strategies in Detail 7-2
Table 7-4. Industrial Sector Investment Assumptions 7-2
Economic Impact Results 7-3
Feasible Strategies 7-3
Table 7-5. Feasible Strategy Average Annual Employment 7-3
Table 7-6. Feasible Strategy Average Annual Earnings 7-3
Potential Strategies 7-4
Table 7-7. Potential Strategy Average Annual Employment 7-4
Table 7-8. Potential Strategy Average Annual Earnings 7-4
Economic Impact Model Assumptions 7-4
Part Eight: Conclusion 8-1
Conclusion and Discussion 8-1
Figure 8-1. GHG Mitigation Strategies (Emissions Reduction) 8-2
Figure 8-2. GHG Mitigation Strategies (Cost) 8-2
The Role of Government Agencies and Institutions 8-3
Federal Actions 8-3
State Actions 8-4
Local Actions 8-4
Individual and Firm Actions 8-5
Concluding Remarks 8-5
Appendix A-l
Carbon Emission Coefficients Appendix A
Utah Fossil Fuel-Based GHG Emissions, 1990-1998 Appendix B
Utah Fossil Fuel-Based GHG Emissions
Forecast Assumptions, 1998-2010 Appendix C
Utah Greenhouse Gas Emissions Inventory
and Mitigation Strategies Appendix D
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I. Carbon Accounting and Mitigation Strategies D-l
Table D-l. C02 Emission Factors and Energy
Cost for Coal and Natural Gas D-l
Figure D-l. Variation of Coal Carbon Coefficients D-3
Figure D-2. Variation of C02 From Coal
Compared to Default IPCC Values D-4
State of Science - Uncertainties in Projections of Human-Caused
Climate Warming, J. D. Mahlman Appendix E
Bibliography B-l
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Greenhouse Gas Reduction Strategies in Utah:
An Economic and Policy Analysis
Executive Summary
I. Background
In 1996, the Utah Office of Energy and Resource Planning (OERP) and the Utah Division of Air
Quality (DAQ) obtained a grant from the U.S. Environmental Protection Agency (EPA) to conduct
research on Utah's contribution to so-called Greenhouse Gas (GHG) emissions as well as the
economics of mitigating these emissions.
Phase I of the research — conducted by DAQ — quantified and established an inventory of the State' s
past and future GHG emissions for the period between 1990 and 2010. The results of Phase I were
published in a report entitled the Utah Greenhouse Gas Inventory inl 997. This baseline cleared the
way for OERP to begin Phase II of the research. Specifically, the objectives of Phase II were
fourfold:
• Refining the greenhouse gas inventory established in Phase I.
• Identifying various GHG mitigation strategies.
• Determining the GHG reduction potential (quantity in tons C02) and cost of various
mitigation strategies.
• Assessing the economic impact of select mitigation strategies.
Table 1. Fossil Fuel GHG Emissions Baseline in Tons CO„ 1990-2010
Year
Residential
Commercial
Industrial
TransDortation
Total
1990
7,755,745
7,773,822
15,257,954
11,695,827
42,483,347
1995
8,545,967
8,928,542
16,897,188
14,373,119
48,744,816
2000
10,009,415
10,833,816
19,158,121
16,672,343
56,673,694
2005
10,762,533
12,352,875
21,095,392
18,437,497
62,648,298
2010
11,573,856
14,092,028
23,289,703
20,410,929
69,366,516
II. Major Findings
This executive summary outlines the maj or findings of Phase II. The following discussion is divided
into three sections that cover the following topics: 1) the fossil fuel emissions baseline, 2) mitigation
strategies, and 3) economic impact.
A. Baseline
Approximately 85 percent of Utah's total GHG emissions result from the consumption of fossil
fuels. Throughout Phase II, energy consumption and related GHG emissions are measured at the end
use or final point of consumption. As shown in Table 1 and Figure 1, fossil fuel-related GHG
emissions have increased dramatically in Utah since 1990 due to rapid population growth and a
Executive Summary
Page ES-1
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strong economy. This trend will likely continue throughout the next decade with fossil fuel-related
GHG emissions reaching over 69 million tons C02 by 2010, an increase of 63.3 percent over the
1990 level. In 1999, the industrial sector was responsible for the largest portion (33.8 percent) of
Utah GHG emissions, followed by the transportation sector (29.4 percent), the commercial sector
(19.0 percent), and the residential sector (17.8 percent). The transportation and commercial sectors
are projected to represent increasing shares of fossil fuel-related GHG emissions.
Non-fossil fuel sources contribute the remaining 15 percent of Utah's total GHG emissions. Non-
fossil fuel emissions are discussed in a separate chapter within the report.
Figure 1. Fossil Fuel GHG Emissions Baseline 1990-2010
70,000 -p
"H—
O
u
~
Residential
~
Commercial
~
Industrial
Transportation
B. Mitigation Strategies
Table 2 summarizes key information regarding the GHG emissions mitigation strategies by sector.
Table 3 ranks individual fossil fuel mitigation strategies by annualized cost. This infonnation is
illustrated in Figures 2 and 3, which provide cumulative supply curves of GHG emissions reduction
by cost. In each figure, various mitigation strategies fall at points along the curve based upon their
annualized project cost per ton for feasible (Figure 2) and potential (Figure 3) levels of emissions
reduction in 2010.
The largest, feasible emissions reductions are anticipated in the transportation sector (1,728 thousand
tons), followed by the commercial sector (458 thousand tons), the industrial sector (340 thousand
tons), and the residential sector (209 thousand tons). On average, mitigation costs per ton are higher
for transportation sector strategies and lower for industrial and commercial sector strategies.
Page ES-2
Executive Summary
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Table 2. GHG Cost and Reduction - Summary by Sector.
Quantity
Cost per ton
Sector Strategies
Feasible
Potential
Feasible Potential
thousand tons C02
Residential
209
1,043
$72.69 $37.57
Commercial
458
2,498
$60.80 $26.53
Industrial
340
646
$49.20 $46.94
Transportation
1,728
3,161
$150.61 $97.77
Total
2,735
7,348
$83.33 $52.20
Table 3. Fossil Fuel Mitigation Strategies Ranked By Feasible $/ton
Sector
Strategy
Quantity
$/ton
Feasib le
Potential
Feasible
Potential
Commercial
Plug Load
24,107
72,321
$2.16
$1.94
Commercial
Bldg commissioning/Recommissioning
97,508
731,310
$2.55
$1.28
Residential
Weatherization (Elec and natgas)
55,392
387,744
$4.36
$3.05
Industrial
Lighting
59,415
94,074
$6.13
$5.52
Transportation
Smart Traffic Lights and Highways
48,027
96,055
$6.62
$6.62
Industrial
Steam System Optimization (h and process h)
82,881
165,761
$12.79
$11.51
Commercial
Variable-speed drive motors
24,620
172,338
$14.27
$10.70
Residential
Lighting
28,772
230,173
$16.23
$12.17
Transportation
Tire inflation
48,027
120,068
$18.87
$18.87
Commercial
Lighting
141,871
898,519
$20.30
$15.22
Residential
Green Power Pricing/Marketing (Wind)
62,008
124,016
$20.75
$18.45
Commercial
Lighting Controls
37,832
283,743
$23.68
$16.91
Industrial
Motors (HVAC)
81,696
155,223
$25.90
$23.31
Residential
Gas water heater conversion
9,599
63,992
$30.44
$20.29
Residential
Premium Refrigerators
9,363
149,811
$44.64
$44.64
Commercial
IIVAC
25,186
125,929
$45.38
$34.91
Industrial
Net Metering
82,521
165,043
$47.81
$47.81
Transportation
Convert vehicles to natural gas
57,257
95,429
$87.86
$87.86
Transportation
Enhanced I&M inspection
48,027
120,068
$94.37
$94.37
Transportation
Telecommuting
35,848
59,746
$107.79
$107.79
Transportation
Rideshare
22,405
44,809
$160.68
$80.34
Transportation
Parking Fees
37,341
74,682
$173.11
$173.11
Commercial
Green Power Pricing/Marketing (Wind)
49,240
98,479
$173.15
$136.81
Commercial
Net Metering
57,446
114,892
$191.26
$191.26
Transportation
Buy out old cars
96,055
240,137
$223.07
$223.07
Transportation
Convert vehicles to LPG
16,270
32,540
$274.86
$274.86
Industrial
Green Power Pricing/Marketing (Wind)
33,009
66,017
$279.31
$220.69
Residential
Net Metering
43,406
86,811
$286.89
$286.89
Transportation
Light Rail Doubled
68,000
160,000
NA
NA
Transportation
Buses Doubled
45,000
45,000
NA
NA
Transportation
Jet Engine Efficiency
28,519
85,557
NA
NA
Transportation
Light Rail
34,000
80,000
NA
NA
Transportation
Heavy-duty Trucks
97,634
146,451
NA
NA
Transportation
Regional (Heavy) Commuter Rail
40,000
80,000
NA
NA
Transportation
Truck-to-rail substitution
180,000
240,000
NA
NA
Transportation
Feebate for new mpg
192,109
480,273
NA
NA
Transportation
55-mph speed limit enforcement
633,961
960,547
NA
NA
Executive Summary
Page ES-3
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^3
a
di
to
Figure 2. Cost vs. Reduction
Feasible
C5
K
C<)
R
$125
$100
$75
C5
O
$50
$25
$0
l:Ll0htlrftSmart Tral
R: Weatherlzatlon (Else and
C:Bldg commlsslonlng/RecommlMlonli
al^mr
T:Tlre Inflation
R: Lighting
C:Variable-speed drive motors
l:Et*am System Optimization (h and pro
fflc Lights and Highways
itgas)
+
I:Motors (HVAC)
C:Llghtlng Controls
:Llghtlnjl:GrsBn Power Pricing/Marks!
+
T:Tslecommutlng
T:Enhanced l&M Inspection
T:Convert vehicles to n
I:Nat Metering
R: P SitflfllftpRefrl gerato rs
er heater conversion
250 500 750
thousand tons C02 (cumulative)
1
1,000
1,250
-------
CJ
r
Figure 3. Cost vs. Reduction
Potential
Co
R
a
ckj
tq
to
$125
$100
$75
si
o
&
$50
$25
$0
hUaTsfi
•mart Traffl
t:W»atherizatlon (Elm
ig/Recommlsslonlng
mmlsslo
: Lights and Highways
and natgas)
-
latlon (h and pro
+
/
R:Ga« water
RzOreWlPfcWWfla
C:Llghtlng Controls
4-
+
T:RI
/
ttsrlng
R:Premlum Refrigerators
heater conversion
ng/Marketing (Wind)
+
f
i
T:Telecommutl
T:Enhancsd l&M
Convert vehicles to natural gas
+
500
1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000
thousand tons C02
-------
C. Economic Impact
OERP analyzed the economic impact of 13 fossil fuel-related mitigation strategies. Four strategies
were considered for the residential sector, six strategies were considered for the commercial sector,
and three strategies were considered for the industrial sector. OERP estimates that these strategies
could reduce Utah GHG emissions by between 678 (feasible) and 3,530 (potential) thousand tons
co2.
The estimated average annual changes in earnings and employment were addressed using an
economic impactmodel. Forsimplicity summary results for both the feasible and potential economic
impact scenarios are summarized in Table 4.
Under the feasible scenario for the selected 13 strategies, Utah average annual earnings were
estimated to increase by more than $8.5 million dollars (0.03 percent), mostly due to investment in
energy efficiency retrofits. Similarly, Utah average annual employment was estimated to increase
by 482 jobs (0.04 percent).
With the potential scenario for the same strategies, the increase in Utah average annual earnings were
dramatically higher at $24.1 million dollars (0.08 percent). Average annual employment was
estimated to increase by 1,623 jobs (0.15 percent).
Table 4. Estimated Average Annual Changes in Earnings and Employment
Economic Impact Scenario
Change in Earnings
Change in Employment
Thousand Dollars
Percent
Jobs
Percent
Feasible
$8,561
0.03%
482
0.04%
Potential
$24,058
0.08%
1,623
0.15%
Page ES-6
Executive Summary
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Part One
Introduction
I. Background
In recent years, the scientific community has conclusively determined that the global atmosphere's
concentration of greenhouse gas (GHG)1 emissions has been rising. These gases, produced from
varied sources worldwide, effectively trap heat in the Earth's atmosphere that would otherwise be
released into space. The growing international scientific consensus is that sustained accumulations
of these gases could directly alter the average temperature of the Earth's surface. In turn, these
modified temperatures may have profound implications for global and regional climate, agricultural
patterns, ecosystems, and even sea level. Though speculated that some regional economies may
benefit from such changes, it remains the general contention that the net effect would likely
compromise the natural environments and economies of most of the world's inhabitants.
In 1988, responding to the increasing weight of scientific findings, the World Meteorological Organ-
ization (WMO) and the United Nations Environmental Program (UNEP) established the
Intergovernmental Panel on Climate Change (IPCC). The IPCC was then charged with the task of
assessing the available scientific, socioeconomic, and technical information in the field of climate
change. Conceding the formidable challenge in identifying the differing sources of GHG emissions,
nevertheless the IPCC concluded that, "the balance of evidence suggests that there is a discemable
human influence on global climate."
Reported to the UN in 1990, the IPCC' s findings were adopted by the General Assembly. The IPCC
report further set the stage for establishing the United Nations Framework Convention on Climate
Change (UNFCCC).
On June 12th 1992, along with 154 nations, the United States signed the UNFCCC in Rio de Janeiro.
The Convention established a legal framework that commits the signatories to voluntary reduction
of GHG emissions or other actions, such as enhancing GHG sinks, at 1990 levels.
In October, the United States became the first industrialized nation to sign the treaty and, one year
later to the month, the Clinton Administration released its Climate Change Action Plan (CCAP),
which called for the Nation to reduce GHG emissions to the 1990 level by the year 2000. In brief,
the CCAP entails a collection of 50 initiatives or strategies that span all sectors of the economy and
concentrate on reducing GHG emissions in a cost-effective manner. Broadly, the initiatives call for
cooperation between government, industry, and the public.
Anticipating these international actions on GHG mitigation and to facilitate these reductions in the
United States in 1990, the U.S. Environmental Protection Agency's (EPA) Climate Change Division
established the State and Local Outreach Program to assist state governments in research on policies
1 Hereafter GHG refers to greenhouse gas; GHGs refers to greenhouse gases.
Part One: Introduction Page 1-1
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to reduce GHG emissions. In 1996, the EPA awarded a research grant to the Utah Office of Energy
and Resource Planning (OERP) and the Utah Division of Air Quality (DAQ) to conduct preliminary
research into the economic cost associated with measures and strategies to reduce state GHG
emissions.
The momentum generated at the 1992 Rio meeting led to the December 1997 Kyoto Protocol which
called for certain nations to reduce their GHG emissions, during the period between 2008 and 2012,
to 5 percent below 1990 levels. According to the Protocol, the United States would be required to
reduced its GHG emissions, during the same period, to 7 percent below its 1990 levels. To date,
however, the United States has not ratified any treaty binding the Nation to the Kyoto Protocol.
II. Scope of Research
For this research, OERP and DAQ have identified several related goals: 1) establish an energy
baseline - that details the structure and pattern of energy consumption in the Utah economy; 2)
identify various GHG emissions mitigation strategies; 3) determine the GHG reduction potential
(quantity in C02 tons) and cost of the selected GHG reduction measures; and 4) when possible,
assess the economic impact of GHG reduction measures.
While about 85 percent of GHG emissions in Utah result from the consumption of fossil fuels, non-
fossil fuel emissions are also significant and will be addressed as well.
III. Methodology
Before mitigation strategies could be evaluated for this research, it was necessary to establish a
baseline of Utah's GHG emissions. Because most GHG emissions in Utah result from fossil fuel
consumption and because non-fossil fuel emissions are difficult to estimate, this research focuses
primarily upon the development of a fossil fuel emissions baseline. This baseline consists of
projected C02 emissions at the end use — i.e. final point of consumption — by economic sector. For
each year between 1990 and 2010, all emissions by source and sector are estimated and totaled. The
baseline provides a yardstick by which the GHG emissions reduction potential of various mitigation
strategies could be evaluated.
A given reduction strategy is first evaluated in terms of its individual capacity for eliminating GHG
emissions. For each mitigation strategy pertaining to each sector, an estimate of GHG reduction
capacity is calculated from engineering estimates and the economic literature. Reduction is defined
according to either of two categories, "feasible" or "potential."
The feasible category describes the likely reduction expected and is based on assumptions regarding
market penetration, in the case of technologies, and political or institutional acceptance in the case
of laws or regulations. The potential category assumes no significant barriers to measure adoption
and, therefore, represents the maximum amount of reduction possible from a given mitigation
measure.
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Part One: Introduction
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With feasible and potential reduction estimated, it is then necessary to identify the cost associated
with implementing a given strategy. Cost calculations are important in determining the ultimate
selection of mitigation strategies, since there is wide variation in the cost per ton among the
strategies.
In this research, mitigation cost is evaluated with respect to an emissions reduction amount per year.
In reality, various strategies maybe initiated in different years. For the purpose of comparison in this
study, however, the mitigation costs for each strategy are calculated assuming that all strategies begin
in the year 2001 and achieve the same level of emissions reduction in each project year.
To ensure comparability in evaluation, the cost-per-ton values for each measure are calculated in
annualized or levelized dollars at a real discount rate of 5 percent. This approach accounts for the
wide variation in fixed and capital costs associated with each measure. Furthermore, the levelized
cost for each measure is evaluated over the same period of estimation; that is, each measure is
viewed as a project that is successively undertaken or "repeated" over a 30-year period from 2001
to 2030. This adjustment ensures that costs for all measures are spread out over a long enough
period so as not to penalize measures with relatively high up-front capital costs and/or longer life-
cycles. Of note, no explicit accounting is made for the likely economy of scale or diminishing
returns that might be realized as more measures of a given type are introduced over the 30-year time
frame. Each reduction strategy is viewed as a discrete project, the scale of which does not vary over
time. As a result, the feasible cost values reported in this study represent the annualized cost over
a 30-year period (from 2001 to 2030) per ton of C02 reduction achieved each project year.
It is vital to bear in mind that the research does not explicitly account for the externalities or
presumed social benefits associated with GHG reduction. For example, sulfur dioxides, nitrogen
oxides, particulates, and ozone formation are all associated with fossil fuel combustion, yet
externality estimates associated with mitigating each pollutant have not been calculated. Because
these estimates are problematic in calculation, the costs ultimately used are estimated according to
financial methodologies and not according to strict economic theory. It should further be noted that
these externalities would, all else equal, lower the net cost of reduction measures. Therefore,
economic estimates maybe considered conservative.
In addition to externalities, other costs have not been directly incorporated. For example, government
programs to improve industrial efficiency involve costs that are not readily measured and, therefore,
are not directly incorporated into the financial calculation. Finally, the analyses typically do not
include time-varying changes in the cost of fuel or technological assumptions.
Finally, the research concludes with an economic impact assessment of GHG reduction investments.
In particular, an input-output model is specified which determines the economic impact of multi-
sector investment in a subset of the selected strategies.
Part One: Introduction
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IV. Report Structure
The following report summarizes the research conducted for Phase II. The report is structured as
follows. Part Two provides a more detailed look into the background of climate change and the
theorized greenhouse effect. It also includes a timeline and discussion of international treaties on
climate change. In addition, Part Two reflects on the debate over the greenhouse effect in the
international science community.
Part Three outlines the development of the Utah Greenhouse Gas Emissions Inventory and the
selection of mitigation strategies. In addition, the maj or types of GHGs are identified and described.
Finally, Part Three outlines OERP's criteria for the selection of mitigation strategies for further
research.
Part Four describes the development and results of the Utah energy baseline. Following a statewide
overview, Part Four details energy use and carbon dioxide emissions for the following sectors:
• Residential
• Commercial
• Industrial
• Transportation
• Electric Utility
Part Five describes various GHG emissions mitigation strategies by sector. Part Five also includes
a cross-sectoral discussion on mitigation opportunities associated with land use planning.
Part Six provides a overview of non-fossil fuel sources of GHG emissions. Various non-fossil fuel
sources are identified and described. In addition, Part Six identifies and evaluates mitigation
strategies for these emissions.
Part Seven details the results of an economic impact analysis of a subset of the mitigation strategies
discussed in Part Five. The change in average annual earnings and employment are estimated for
both feasible and potential scenarios.
Part Eight concludes the report by summarizing major findings and outlining the potential roles of
various parties in GHG mitigation.
Appendixes present additional information.
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Part One: Introduction
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Part Two
The Greenhouse Effect and Global Initiatives
I. Background and State of the Science
Atmospheric conditions are described in terms of either weather or climate. Weather refers to a
specific condition in the atmosphere at a given place at a set time and characterizes these varying
conditions in terms such as precipitation, solar insolation, humidity, and fog. Weather may also be
measured in terms of rainfall, temperature, and barometric pressure. Typically a local phenomenon,
weather can affect a large area as in the case of a hurricane which spans over a larger region.
Climate, in comparison, explains average weather conditions over a period of time, usually 30 years
or more. As with weather, climate patterns may be analyzed locally and regionally; however, climate
is described with respect to very large regions including continents, hemispheres, or even the Earth.
Climate is less difficult to predict than weather because the latter is a highly localized phenomenon.
Dramatic changes in weather conditions are not inherently significant and frequent variations are
expected. A rapid change in climate, on the other hand, is startling even if it is expected, and such
a change would rarely register in a decade. Because climate patterns represent averages over longer
time periods and larger areas, they are easier to predict than weather patterns. Granted climatic
predictions are still fraught with uncertainty, but scientists can forecast climate conditions with a
much higher level of certainty than they are able to forecast weather conditions.
A. Climate and Weather in Context: A History of Climate Change
The history of the Earth's climate is as old as the planet itself. Yet the passage of time has blurred
our vision of this history, providing us with few facts upon which to base conclusions about trends
in climate change. Today, trends in climate are inferred from analyzing weather data produced from
instrument measurements, such as thermometers, barometers, or weather balloons. Such data is
critical for understanding modern climate conditions. Regrettably, however, these records only exist
for a tiny fraction of the Earth's history.
It is difficult, if not impossible, to understand our modern climate by relying solely on data provided
by modern record keeping on climatic indicators. Indeed, the past holds the key to a better
understanding of climate phenomenon. Earlier climatic trends can be inferred "by the study of
natural phenomena which are climate-dependent, and which incorporate into their structure a
measure of this dependency" (Bradley, 1985)]. Such inferences provide a proxy recordwhich serves
as the foundation of paleoclimatology, or the study of climate predating instrumental measurements.
In providing an historical context, proxy data serves as a lens through which to view the Earth's
modern climate.
Proxy data includes inferences from flora, fauna, tree rings, ice cores, and coral. Though such data
capture elements of climate as far back as several millennia, the relatively small number of locations
measured does not yet allow scientists to build a complete picture of the global climate. Clearly, the
further one reaches back in time, the less reliable and detailed the data sample becomes.
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It is possible, though, to construct a proxy data set of the world's climate for the past several
centuries which allows for a meaningful comparison of climate before and after the industrial
revolution. This is important since a growing consensus among scientists studying global wanning
is that events following the industrial revolution, specifically increases in atmospheric greenhouse
gas resulting from human behavior, have contributed to global wanning. By comparing the climates
before and after the industrial revolution, scientists are better able to speculate on the link between
human behavior and changes in climate in the post-industrial era. In addition, a picture of the world's
climate spanning the past several centuries also allows observers to mark the natural degree of the
climate's variability.
Figure 2-1.
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Perhaps the most complete set of climate data for the past several centuries is the reconstruction of
the Northern Hemisphere by Mann, Bradley, and Hughes (1998). This data accounts for six centuries
of proxy data based on a wide range of natural phenomenon. In compiling various samples from
many points in the Northern Hemisphere, these researchers have minimized the potential limitations
of any one proxy indicator while simultaneously reducing the possibility of human error. Though
somewhat limited in its focus on the Northern Hemisphere, the data provides a reputable docu-
mentation of climate affecting a wide range of sites. For the purpose of this report, this proxy record
is the best available source on global climate.
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Part Two: The Greenhouse Effect and Global Initiatives
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Figure 2-2.
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The reconstruction shows the variability of climate (see Figure 2-1) and highlights several important
trends such as the relative extremes in temperature. The mid-fifteenth century, for example, is the
coolest period during the time series, a period commonly known as "the Little Ice Age." As shown
in Figure 2-1, the twentieth century is the wannest period: nine of the wannest years in this time
series (through 1997) have occurred in the past 11 years. One also notes that periods within the
seventeenth and nineteenth centuries were substantially wanner than the cool periods within the
sixteenth and eighteenth centuries. Mann, Bradley, and Hughes note the warming of the current
century by comparing the mean temperature of this century to the temperatures of those in previous
centuries. Strikingly, temperatures in previous years tend to fall well below the mean of the current
century. It is important to note, however, that unusual weather patterns do not in themselves confirm
the hypothesis of human-induced wanning. However, this proxy record does provide evidence of the
Earth's wanning, which is not a matter of dispute among scientists. (Mahlman, 1997).
B. The Science of the Greenhouse Effect
An important factor influencing climate conditions is the atmosphere's ability to trap sunlight once
it has passed through the Earth's atmosphere. Sunlight is shortwave radiation that travels through
the Earth's atmosphere with little resistance. As sunlight reaches the Earth's surface, the sunlight
is absorbed by the Earth. Upon return to the atmosphere, however, sunlight is transfonned into
thennal or long-wave radiation.
This transfonnation is significant because greenhouse gases in the atmosphere do not allow all of
the longwave radiation to pass through the atmosphere. The longwave radiation that does not pass
through the atmosphere is retained, at least temporarily, in the atmosphere; the remainder that is able
to pass though the atmosphere continues to move out into space.
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This process of transforming shortwave radiation into long-wave radiation and then retaining a
portion of this radiation is commonly known as the greenhouse effect. Some scientists estimate that
without this simple process the Earth's surface would be approximately 55 F cooler than it is today.
Greenhouse gases that occur naturally in the atmosphere include water vapor (H20), carbon dioxide
(C02), methane (CH4), nitrous oxide (N02), and ozone (03). Some human-made compounds are also
greenhouse gases, including chlorofluorocarbons (CFCs) and partially halogenated fluorocarbons
(HCFCs), hydro fluorocarbons (HFCs), and other compounds such as perfluorinated carbons (PFCs).
Under current conditions the greenhouse effect is critical to supporting life as we know it; a sub-
stantial shift in the equilibrium conditions underlying the greenhouse effect due to increasing
anthropogenic emissions of GHGs could potentially have a detrimental effect on life as we know it.
II. International Treaties
A. Framework Convention on Climate Change
Held in Rio de Janeiro in 1992, the Framework Convention on Climate Change produced a
document stipulating that 155 signatory nations stabilize anthropogenic GHG emissions to prevent
dangerous interference with the climate system. Neither exact levels were set nor reduction targets
made binding at the meeting.
The United States ratified the UNFCCC in 1992 and, by September 1999, another 180 countries
ratified the framework. While exact limits were not set, Article 4 provided guidelines for emission
reduction commitments. The United States, for example, had assumed the non-binding commitment
to reduce its net GHG emissions to 1990 levels by the year 2000.
B. Kyoto Protocol
In early December 1997, over 160 nations assembled in Kyoto, Japan, to develop binding limits on
GHG emissions. After 10 days of negotiations, an agreement was reached that, if ratified, would
require the world's developed nations and nations with economies in transition (collectively referred
to as Annex I parties) to reduce their combined annual average GHG emission levels to 5 percent
below 1990 levels between 2008 and 2012. The United States agreed to reduce emissions to 7
percent below 1990 levels.
Under Article 6, Joint Implementation projects include those between Annex I parties. Projects
between Annex I parties and developing countries are covered under Article 12, known as the Clean
Development Mechanism (CDM). Under CDM, for example, U.S. companies could invest in clean
technologies or develop forestry and sequestration projects abroad and receive credit for emissions
reductions.
Although the United States placed considerable pressure on developing nations to agree to an
emissions cut of their own, the effort was unsuccessful. Developing nations believe that limits on
GHG emissions would pose unacceptable constraints on their economic growth and development.
Nations such as China and India are determined to first raise their standard of living before agreeing
to any reductions. They believe that as the leading producers of GHGs, the United States, Europe,
Japan and the other developed countries should be the first to make reductions.
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Before the accord will have any relevance for the United States, however, it must be ratified by the
Senate. Many senators and business leaders have expressed strong distaste for the accord since the
refusal of developing nations to agree on emissions reductions would force the United States and
other developed countries to shoulder the burden of emissions reductions in the near future, which
could have significant economic implications. In the face of significant opposition to the Kyoto
treaty in the Senate, the Clinton administration may not even submit the treaty for ratification before
2000. As a result, although the United States has already implemented a national Climate Change
Action Plan, it maybe several years before the United States begins to implement a national plan for
meeting the emission reduction targets specified under the Kyoto Protocol. (Hanscom and Jancart,
1997).
During November of 1998 delegates from 150 nations reconvened to negotiate strategies for fighting
global warming. The U.S. representatives arrived under a cloud of scrutiny from critics of Clinton's
support of the Kyoto Treaty in the Senate and from U.S. businesses (Krix, 1998). Prior to the
negotiations the Senate unanimously passed S. Res. 98, which states that the United States should
not sign an agreement that fails to include provisions ensuring that developing countries undertake,
limit, or reduce GHG emissions for developing country parties within the same compliance period.
To the surprise of many, the American delegation-under the direction of Undersecretary of State
Stuart E. Eizenstat-further upset the president's critics by signing the 1997 Kyoto Treaty. Though
largely a symbolic gesture (since the Senate must ratify the treaty before it goes into effect), the
signing did heighten the conflict between the Senate and the White House and fueled the momentum
for action ignited in Kyoto.
Senator Frank Murkowski (R-Alaska), Chairman of the Natural Resource Committee said:
"The president made two grave errors in signing the treaty. First, he undercut the leverage of his own
negotiators currently meeting in Buenos Aires. Second, he defied the bipartisan views of the Senate
which unanimously voted in support of a resolution explicitly asking the president not to negotiate or
sign a treaty that did not include the full participation. Thus, he probably doomed this treaty." (Fizanz,
1998b).
Though it remains to be seen what should come of the treaty, the president certainly faces serious
opposition to ratification in the Senate.
In spite of the criticisms leveled by his critics, President Clinton's stand at Buenos Aires will be
remembered as somewhat of a breakthrough. Undersecretary Eizenstat made real gains in persuading
other nations to accept the administration's approachto addressing global warming. The president's
market-based approach to climate change, originally viewed with skepticism in Kyoto, was embraced
by a handful of developing nations in Buenos Aires. This approach consists of three elements: 1)
joint implementation under Article 6; 2) the Clean Development Mechanism under Article 12; and
3) international trading under Article 17.
Arguably, the most significant breakthrough of the proceedings came in the final hours of the talks
as two developing nations (Argentina and Kazakhstan) agreed to adopt voluntary limits on their own
emissions. This step moved beyond the agreement secured in the Kyoto Treaty and may be viewed
as a direct challenge to the block of developing nations still refusing to adopt emissions limits. As
a result, it is reported that more than a dozen countries are considering the adoption of similar limits.
Part Two: The Greenhouse Effect and Global Initiatives
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Most commentators credit the financial incentives built into the Kyoto Mechanisms as partly
responsible for the recent adoption of such limits.
III. The International Science Community
There is no dispute among climatologists, meteorologists, paleoclimatologists, and other scientists
in related fields that the Earth's climate is indeed warming. Furthermore, there is a general con-
sensus that human activity plays a role, albeit unclearly defined, in promoting the increase in GHGs
(particularly C02, methane, and nitrous oxide which all occur naturally). The claim that GHG levels
have a strong relation to temperature and climate is generally accepted as well.
Since 1800, C02 atmospheric concentrations have increased by 25 percent, methane concentrations
have more than doubled, and nitrous oxide concentrations have risen by approximately 80 percent
(Division of Air Quality, 1996). CFCs also contribute to GHG formation. Between the 1950s until
the mid-1980s, when international concern over CFCs grew, the use of these gases increased nearly
10 percent per year. Consumption of CFCs is declining quickly as these gases are phased out under
the "Montreal Protocol of Substances that Deplete the Ozone Layer." Use of CFC substitutes that
contribute to global warming, to a lesser extent, is expected to grow substantially.
The United Nations and the World Meteorological Organization established the Intergovernmental
Panel on Climate Change (IPCC) in hopes of creating an authoritative voice to explain climate
change and its implications. While some disagree with all or parts of the IPCC's findings, the
research is embraced by U.S. scientists and government agencies supporting the United States
Climate Program.
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Part Two: The Greenhouse Effect and Global Initiatives
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Part Three
Utah Greenhouse Gas Emissions Inventory and Mitigation
Strategies
I. Phase I: The Utah Greenhouse Gas Inventory
To effectively develop policies to reduce GHG emissions, a state must first identify its
anthropogenic emissions and estimate the contribution of these emission sources to overall radiative
forcing. The State of Utah's Phase I report, (The Utah Greenhouse Gas Inventory, 1996), provides
a detailed accounting of GHG production in Utah during 1990 and 1993. Numerous GHGs are
emitted in Utah, the most common being carbon dioxide (CO2), methane (CH4), and nitrous oxide
(N02). Both inventories outline a rudimentary historical baseline of Utah's GHG production with
emissions measured by translating the volume of particular gas into its corresponding CO2
equivalent. That is, for each ton of gas released into the atmosphere, the amount of CO2 with the
equivalent heat-trapping effect is computed. By using these standard CCVequivalent units,
emissions of various gases may be compared and added.
The inventory revealed a previously unknown fact: Utahns produce almost twice as much GHG per
capita as the national average. Utah emissions in 1993 (72 million tons C02 equivalent) accounted
for more than 1.2 percent of total U.S. emissions, while Utah represents only 0.7 percent of the
country's population. This means Utah produced 1.7 times more CO2 equivalent per person than did
the average U.S. state.
A. Carbon Dioxide
The primary source of Utah's GHG emissions is not excessive motor fuel consumption as might be
expected but, rather, CO2 from coal burning for the production of electricity. Each year Utah's five
major power plants burn nearly 13 million tons of coal. In 1993, the electric utility sector alone
accounted for nearly 50 percent of Utah's GHG emissions, dwarfing both the transportation and
industrial sector emissions.
In contrast, many states have a blend of electric generating capacity, including hydropower, nuclear
power, and other low CCVemitting generation in addition to coal-fired steam generation. In
California, for example, emissions from power generation account for less than 10 percent of the
state's C02 emissions. (It should be noted that California imports a great deal of coal-fired
electricity from Utah, yet the associated CO2 emissions appear on Utah's inventory.)
Utah's second leading source of GHGs is the transportation sector. Motor fuel combustion for
transportation released nearly 13 million tons of CO2 in 1993 and accounted for 18 percent of all
emissions. Fuel requirements for transportation have increased dramatically during the last several
years, and CO2 emissions have increased proportionately.
Utah's heavy industrial operations such as Geneva Steel, Kennecott Copper and several cement and
lime producers consume large quantities of coal, natural gas and various petroleum products to
produce process heat. Releasing 9.8 million tons of C02 in 1993, Utah's industrial sector contributed
more than 13 percent of the state's GHGs.
Part Three: Utah Greenhouse Gas Emissions Inventory and Mitigation Strategies
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Burning mostly natural gas, the residential and commercial sectors are responsible for the remainder
of Utah's fossil fuel CO2 emissions (7 percent of total emissions).
In total, fossil fuel consumption for electricity generation, transportation, industry, accounts for the
vast majority (more than 85 percent) of Utah's GHG emissions.
Additional CO2 is released by a variety of production processes, including lime production, cement
production, and limestone use. Together these activities produced 1.7 million tons of CO2 through
non-energy activities.
B. Methane
The second most abundant GHG produced in Utah is methane (CH4). In 1993, more than 400,000
tons were released into the atmosphere and accounted for approximately 12 percent of Utah's GHG
emissions. (Note: In terms of heat trapping ability, methane's "global warming potential" is 21 times
greater than that of CO2).
The largest source of methane emissions in Utah is coal mining. In coal operations, methane is
released prior to extraction to preclude the risk of explosion and fire. Although some is extracted
and sold, venting is typically the most economically viable alternative. Approximately 213,000 tons
of methane were released from underground coal mines in 1993, accounting for 6.43 percent of
GHG emissions.
Methane is also released during oil and gas production, as well as during oil refining. A by-product
of these operations, methane is often vented or flared. In addition, some is unintentionally leaked
from oil and gas distribution systems during transport. Although difficult to assess, methane
emissions from the oil and gas sector are placed at more than 60 thousand tons. These sources
represent approximately to 1.83 percent of the state's total GHG emissions.
Domesticated animal food digestion is responsible for a notable share of Utah's methane emissions.
In 1993, livestock produced more than 73 thousand tons of methane, which is more than 2 percent
of total GHG emissions. Dairy and beef cattle were largely responsible for this total.
Cows are not the only animals involved in Utah methane production. In the process of anaerobic
decomposition, microbes transform animal and human wastes into methane. By digesting human
wastewater, animal manure and the contents of landfills, microbes generated more than 63 thousand
tons in 1993. Emissions from these sources amounted to just under 2 percent of Utah's total GHG
emissions.
C. Nitrous Oxide
Utah also produces a third important GHG, nitrous oxide (N2O). In 1993, approximately 450 tons
of nitrous oxide were released through the use of fertilizer, a relatively small amount representing
0.17 percent of total GHG equivalent emissions.
D. Utah Forests
Forest and land-use management have important impacts on atmospheric C02. As they grow and
develop, living trees absorb CO2. When trees are harvested for milling or fuel use, or when they die
and decompose, stored CO2 is released back into the air. In 1993 approximately 35 thousand more
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Part Three: Utah Greenhouse Gas Emissions Inventory and Mitigation Strategies
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tons of CO2 were absorbed by trees than were released from trees. In effect, Utah trees absorbed
about 0.05 percent of the state's GHG emissions.
II. Goal of the Utah Greenhouse Gas Mitigation Plan
The goal of Utah's Phase II is to identify a range of GHG mitigation strategies that will reduce
forecasted emissions. Strategies may target reductions in certain sectors or concentrate on specific
GHGs.
As evidenced by the research in Phase I, the majority of Utah's GHGs are released from the
combustion of fossil fuel energy. Mitigation strategies include projects and programs designed to
improve energy efficiency and reduce fossil fuel consumption.
The study analyzes strategies in seven major sectors: residential, commercial, industrial,
transportation, electric utilities, non-fossil fuel sources, and land-use planning. The strategies can
be divided into three major types: 1) reducing energy use through energy efficiency; 2) reducing
GHG emissions through energy substitution; 3) reducing the amount of GHG emissions from CO2
energy production.
Phase II introduces Utah policymakers to a broad range of mitigation strategies. These strategies are
evaluated against several criteria, as described below. Each strategy will be examined in detail, and
— where possible - the cost per ton of CO2 emissions reduced will be estimated. In this way, each
strategy may be compared on a cost-effectiveness basis and ranked accordingly.
Once a set of strategies has been outlined, the corresponding economic impact will be assessed using
an input-output model. Economic impact analysis will estimate the overall effect of GHG reduction
on the Utah economy and employment levels.
Utah currently has no formal plan to develop a GHG reduction program. However, should the state
choose to do so, the Phase II report may provide the foundation for future research. Phase II, then,
is intended to serve as a springboard for future discussions in Utah about how to reduce GHG
emissions.
III. Criteria for Selection of Mitigation Strategies
Criteria are standards for assessing alternative mitigation strategies [States Guidance Document 4-1],
Rather than a strict set of guidelines, the criteria employed in Phase II are guidelines to ensure a
comprehensive and consistent consideration of relevant constraints when selecting mitigation
strategies. The following are the criteria in order of priority that this report uses:
¦ Amount of GHG Emissions Reduced. Every strategy should reduce current or future GHG
emissions. Strategies that fail to do so are not considered.
¦ Participation Across Utah's Economic Sectors and Geographic Locations. Different strategies
will affect some sectors or locations more than others. As a matter of principle, this report tries
to distribute the costs and benefits of reducing GHGs in an equitable manner. Since all sectors
contribute to Utah's GHG emissions, all should share in the reduction effort.
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¦ Cost Efficiency. Any attempt to reduce GHGs will entail costs. However, some strategies are less
costly than others. Furthermore, some strategies lead to a return on an initial investment that
ultimately recovers all or some of the up-front costs. This report gives preference to strategies that
cost less relative to other strategies with similar GHG reduction potential. Private and public
sector costs and savings are recognized.
¦ Ancillary Benefits and Costs. Some mitigation strategies affect other state priorities, either directly
or indirectly. Various strategies produce benefits by enhancing environmental quality, social
welfare, or government revenue. Costs can occur when a strategy negatively affects one of these
items or other legitimate competing values. Reduced air pollution and traffic congestion are
generally viewed as benefits, not costs, of GHG mitigation.
¦ Political Feasibility. Public acceptability is an important consideration of mitigation strategies.
Of course, reducing GHGs is not without costs; clearly, meaningful reductions will only come
with some sacrifice and effort. However, as a matter of principle, this report tries to highlight
policies that will likely face less organized resistance than others. In the case that the state adopts
an official plan to reduce GHG emissions, public involvement and education should be used to
help gain perspective and provide additional information. Including the public may also help build
public support.
In addition to the substantive criteria above, the following process-oriented criteria are also
employed in the selection of mitigation strategies.
¦ Measurability. This report recognizes that strategies that are measurable in terms of cost and
quantity of GHG reduction may prove to be more valuable to policy makers and the public at-large
than those strategies that are not measurable. Benefits of measurablity may include more accurate
forecasting of individual strategies and more value in comparing various strategies. Wherever
possible the strategies are quantified both in the amount of emissions reduced and in terms of cost
(EPA, 1995).
Page 3-4
Part Three: Utah Greenhouse Gas Emissions Inventory and Mitigation Strategies
-------
Part Four
Utah Energy Baseline
I. Overview of Utah Energy Use and Greenhouse Gas Emissions
A. Utah Energy Use by Fuel and Sector
To identify the appropriate GHG mitigation strategies for all energy-consuming sectors in the state,
it is first necessary to develop a statewide energy baseline that accounts for sector-by-sector
consumption by fuel use and end-use technology. This section provides an overview of Utah's
baseline energy use and C02 emissions. Although most of the Utah energy dataset exists for the
period 1960-1998, the period examined spans 1990 to 1998 to better represent more recent history
and the structure of Utah's energy economy.
Across Utah's economy approximately 85 percent of Utah's total C02-equivalent emissions result
from fossil fuel consumption.
To provide a basis of the role of these fuels in the
state's economy, Table 4-1 gives the carbon and
C02 content of coal, petroleum products, and
natural gas. The measure of pounds of carbon per
million Btu is known as the carbon coefficient. In
the case of petroleum products, the carbon factor is
a weighted average of several fuels. In analogous
fashion, a CO2 factor is reported in the right-hand
column, which measures tons of C02 per trillion Btu. To give a sense of scale, note that 1 million
Btu is not a particularly large quantity of energy, since the typical Utah household (not including
transportation) uses about 165 million Btu a year. Of further note, methane and other GHG
emissions are typically reported in tons of C02-equivalent units.
B. Methodology
Establishing an energy baseline is somewhat problematic. A fundamental choice must be made
whether to measure energy used directly for an application such as power generation ("direct
accounting") or indirectly at the end use in applications such as electric motors or appliances ("end
use accounting"). In the case of the former strategy, the methodology is straightforward: 1) first, for
each fuel, count the physical units of consumption, such as barrels, cubic feet, or short tons; 2)
convert the physical units to energy units (million Btu); 3) multiply by the carbon coefficient (which
translates million Btu to carbon pounds); 4) adjust for stored and oxidized carbon; and 5) convert
to tons of C02.
Because the "end use" methodology accounts for energy use at the final point of consumption - the
last link in the energy delivery chain - all of the thermodynamic losses associated with moving
energy from the point of production to the point of consumption are accounted for in end-use data.
Specifically, these losses relate to the conversion of fuel to electricity, the movement of power over
great distances by transmission wires, and the voltage transformations required to provide safe and
Table 4-1. Carbon Content of Fossil Fuels
Pounds of
Tons of
Carbon per
C02 per
Million Btu
Trillion Btu
Coal
56.0
102,667
Petroleum Products
43.0
78,833
Natural Gas
31.9
58,483
Part Four: Utah Energy Baseline
Page 4-1
-------
Table 4-2. Utah C02 Emissions by Energy Source, Excluding Electricity Exports (in thousand
tons)
Natural
Motor
Other
Electric
Electric
Coal
Gas
Gasoline
Petroleum
Sales
Losses
Total
1990
5,370
7,333
6,825
6,295
5,226
11,431
42,480
1991
5,269
7,967
7,098
6,620
5,398
11,745
44,103
1992
4,736
7,282
7,306
6,637
5,622
12,008
43,592
1993
4,514
8,286
7,687
6,606
5,724
12,093
44,909
1994
4,680
7,971
7,930
6,707
6,056
12,637
45,982
1995
4,409
9,164
8,476
7,378
6,264
13,050
48,741
1996
4,435
9,524
8,639
8,195
6,739
14,024
51,554
1997
4,365
9,760
8,987
8,849
6,914
14,359
53,234
1998
4,680
9,911
9,344
8,888
7,024
14,622
54,469
reliable power to the end user. Table 4-2, which describes C02 emissions by energy source,
includes categories for both the actual electricity supplied to the end user (sales) and the associated
losses in delivering this electricity.
As apparent from Table 4-2, electricity and associated losses represent a significant share of total
GHG emissions. By comparison, in the "direct accounting" methodology, the total fuel consumed
would account for the thermodynamic losses as "extra" fuel consumed to make up for the energy lost
in the process of delivery. Both methodologies provide comparable estimates of carbon emissions
but differ in accounting approaches.
The baseline analysis in this report employs the "end use" methodology. This approach is favored
because it begins with an accounting, by end-use sector, of the major uses of energy. Therefore, it
is easier to target specific GHG mitigation measures to specific energy uses. The end-use sectors
are the residential, commercial, industrial, and transportation sectors. In the residential sector, for
example, end uses include refrigerators, water heaters, and other household appliances. For the
commercial sector, primary end uses include lighting, refrigeration, and heating, ventilation, and air
conditioning (HVAC). Industrial sector processes are used in manufacturing. Motor gasoline, diesel
fuel, and jet fuel used by automobile, truck, air, and rail travel and freight are examples of end uses
in the transportation sector.
Table 4-3. Utah C02 Emissions by Energy Source, Excluding Electricity Exports (as a percent)
Natural
Motor
Other
Electric
Electric
Coal
Gas
Gasoline
Petroleum
Sales
Losses
Total
1990
12.6%
17.3%
16.1%
14.8%
12.3%
26.9%
100.0%
1991
11.9%
18.1%
16.1%
15.0%
12.2%
26.6%
100.0%
1992
10.9%
16.7%
16.8%
15.2%
12.9%
27.5%
100.0%
1993
10.1%
18.5%
17.1%
14.7%
12.7%
26.9%
100.0%
1994
10.2%
17.3%
17.2%
14.6%
13.2%
27.5%
100.0%
1995
9.0%
18.8%
17.4%
15.1%
12.9%
26.8%
100.0%
1996
8.6%
18.5%
16.8%
15.9%
13.1%
27.2%
100.0%
1997
8.2%
18.3%
16.9%
16.6%
13.0%
27.0%
100.0%
1998
8.6%
18.2%
17.2%
16.3%
12.9%
26.8%
100.0%
Page 4-2
Part Four: Utah Energy Baseline
-------
In Utah, about 95 percent of electric power generation is coal-fired, with the remainder comprised
of natural gas, light fuel oil, and hydroelectric power. In addition, Utah exports significant
electricity, most of which consists of power sales to Los Angeles Department of Water and Power
(LADWP).
Table 4-4. Average Annual Growth Rate in C02 Emissions, by Energy Source
Coal
Natural
Gas
Motor
Gasoline
Other
Petroleum
Electric
Sale
Electric
Losses
Total
1991
-1.9%
8.6%
4.0%
5.1%
3.3%
2.8%
3.8%
1992
-10.1%
-8.6%
2.9%
0.3%
4.2%
2.2%
-1.2%
1993
-4.7%
13.8%
5.2%
-0.5%
1.8%
0.7%
3.0%
1994
3.7%
-3.8%
3.2%
1.6%
5.8%
4.5%
2.4%
1995
-5.8%
14.9%
6.9%
9.9%
3.4%
3.3%
6.0%
1996
0.6%
3.9%
1.9%
11.0%
7.6%
7.5%
5.8%
1997
-1.6%
2.5%
4.0%
7.0%
2.6%
2.6%
3.2%
1998
7.2%
-0.2%
4.0%
3.9%
2.0%
2.0%
3.2%
TOTAL
-12.9%
35.2%
36.9%
41.2%
34.4%
27.9%
28.2%
Table 4-5. Utah C02 Emissions by Energy Source and End-Use Sector in 1998 (in thousand tons)
Natural
Motor
Other
Electric
Electric
Coal
Gas
Gasoline
Petroleum
Sales
Losses
Total
Residential Sector
164
3,440
0
101
1,953
4,066
9,724
Commercial Sector
332
1,877
9
269
2,522
5,251
10,281
Industrial Sector
4,185
4,416
139
1,854
2,549
5,306
18,448
Transportation Sector
0
177
9,196
6,575
0
0
16,016
All Sectors
4,680
9,911
9,344
8,888
7,024
14,622
54,469
Overall, C02 emissions from coal have declined from 5.4 to 4.7 million tons in the 1990s, a total
decline of 12.8 percent, or about 1.6 percent a year. The use of coal has declined in the industrial
sector but especially in the residential and commercial sectors, which use small amounts. In contrast,
C02 emissions from natural gas have increased from 7.3 to 9.9 million tons in the decade, a total
increase of 35.1 percent or about 4.4 percent a year.
Other petroleum products are distillate fuel oil, residual fuel oil, and LPG. C02 emissions from these
Table 4-6. Utah C02 Emissions by Energy Source and End-Use Sector in 1998 (as a percent)
Natural
Motor
Other
Electric
Electric
Coal
Gas
Gasoline
Petroleum
Sales
Losses
Total
Residential Sector
0.3%
6.3%
0.0%
0.2%
3.6%
7.5%
17.9%
Commercial Sector
0.6%
3.4%
0.0%
0.5%
4.6%
9.6%
18.9%
Industrial Sector
7.7%
8.1%
0.3%
3.4%
4.7%
9.7%
33.9%
Transportation Sector
0.0%
0.3%
16.9%
12.2%
0.0%
0.0%
29.4%
All Sectors
8.6%
18.2%
17.2%
16.3%
12.9%
26.8%
100.0%
Part Four: Utah Energy Baseline
Page 4-3
-------
products have increased from 6.3 to 8.9 million tons in the decade, a total increase of 41.1 percent,
or about 5.1 percent a year. In this category, distillate fuel and LPG have increased while residual
fuel consumption has decreased. Motor gasoline has increased from 6.8 to 9.3 million tons, a total
increase of 36.9 percent, or about 4.6 percent a year. Finally, combined electricity sales and
associated losses have increased from 16.7 to 21.6 million tons, a total increase of 30.0 percent, or
about 3.7 percent a year.
The Utah C02 baseline inpercentage terms is shown in T able 4-6. Note the significance of electricity
losses as a percentage of total emissions. These
losses alone are roughly twice the level of any fuel
used directly in any application. Table 4-4 shows the
year-by-year changes in emissions by source.
Table 4-7. Utah Residential Electricity Use
Consumption
(million kWh)
Households
(thousands)
Household
Average
(kWh)
1990
4,246
564.1
7,526
1991
4,460
572.0
7,797
1992
4,505
587.8
7,664
1993
4,726
605.6
7,804
1994
5,009
623.0
8,040
1995
5,041
640.8
7,866
1996
5,481
663.7
8,259
1997
5,660
692.0
8,179
1998
5,756
76.4
8,034
C. The Matrix of Total Energy Use and C02
Emissions
Utah's total C02 emissions for 1998 are displayed
by energy source and end-use sector in Table 4-5.
The share of each fuel's contribution to total
emissions is shown in Table 4-6.
Electricity sales and their associated losses
contribute significantly to GHG emissions. Electric
I tali Population (Jrowth
I'tail's population is growing Taster llian llial
of any oilier stale in the nalion. at a rale of 2.6
percent annually compared lo 1.1 percent
annually nationwide. Contrary lo popular
belief, most of ill is grow ill is inlernally-
generaled. Population grow ill is made up of
two components: llie difference of ill-
migration compared willi oiil-migralion and
llie difference of number of birllis relative lo
number of deaths. Most of I'tali's growth
stems from its high binli rale, outpacing any
stale in the I'niled Stales. Add this lo a
substantial amount of in-migralion. and I 'tali
growth is indeed impressive.
In terms of (iIKi emissions, this growth is
important. My delinilion anthropogenic emis-
sions conic from people: population growth,
therefore, results in a proportional increase in
emissions, assuming llial per capita emission
rales are held constant. The I 'tali (ireenhouse
Inventory reveals a prev iously unknown fact:
I'lahns produce almost twice as much
greenhouse gas per capita as the national
average. I'tali emissions in 1W3 <~2 million
tons of CO. equivalent) accounted for more
than 1.2 percent of total I '.S. emissions, vv hi Ic
I'tali represents only 0." percent of the I'.S.
population. This means I'tali produced 1."
times more CO. equivalent per person than
did the average I'.S. state.
These two factors, a growing population and
a high per capita emission rale, lead lo
tremendous growth in(ill(i emissions. Any
emissions goal llial is lied lo a benchmark set
lo a point of lime will likely pose serious
challenges lo I 'tali.
Page 4-4
Part Four: Utah Energy Baseline
-------
losses are approximately 2.08 times the amount of electric sales. Combined electricity sales and
losses represent about 39.7 percent of total C02 emissions. Petroleum products account for 33.5
percent and dominant the transportation sector. Natural gas contributes 18.2 percent, while coal
represents 8.6 percent. Again, it is importantto emphasize that in Utah about 95 percent of electricity
is coal-fired. If the C02 accounting had started with the fuel input at electric power plants, and not
considered end-use electricity, then coal would have been the largest source. One should, therefore,
appropriately interpret the electricity sales and losses as 95 percent coal in origin.
II. Utah Residential Sector and Carbon Dioxide Emissions
A. Overview of Aggregate Trends
In Utah's residential sector, electricity and natural gas are the two primary energy sources. Through
Table 4-8 Utah Residential Natural Gas Use the 199°S' both residential electricity and natural gas
use have increased, generally tracking the state's
rapid growth in population. According to Table 4-7,
between 1990 and 1998, residential electricity
consumption increased from 4.2 to 5.8 billion
kilowatthours (kWh), a 36.0 percent increase overall.
Natural gas demand (see Table 4-8) increased from
43.4 to 56.8 billion cubic feet (bcf), a 30.9 percent
increase overall. For electricity, this trend represents
an annual average growth rate of 4.4 percent in the
current decade. Natural gas has increased less rapidly
with an annual average growth rate of 3.9 percent.
Total energy use is often disguised by the growth in
overall population. For the residential sector, abetter
indication of the growth in energy use is given by the change in average household energy use.
Electricity demand hasgenerally increased in Utah when evaluated in terms of average household
use. Beginning the decade at about 7,500 kWh, the most recent average is now about 8,000 kWh.
Both total and average residential electricity demands are shown in Table 4-7.
For natural gas, the growth pattern in energy use is more erratic. Overall residential natural gas use
has been growing with population, but average household use has remained roughly constant. Both
total and average natural gas demands are shown in Table 4-8. In Utah, natural gas is the primary
winter heating fuel and its use is weather-dependent. While unusually cold winters spike natural gas
demand, mild winters result in low or moderate natural gas use. The average household natural gas
consumption has tracked between 93 mcf and 111 mcf.
Household average consumption may be readily compared to the average electricity consumption
for all U.S. households. In the 1990s, the national average household electricity consumption was
approximately 23 to 28 percent higher than Utah's. During this period, the national average
residential electricity consumption per household has held at over 10,000 kWh per household each
year. For natural gas, the United States average household use in the 1990s was about 90 mcf per
year.
Consumption
(m mcf)
Customers
(thousands)
Customer
Average
(mcf)
1990
43,424
453.0
95.9
1991
50,572
455.6
111.0
1992
44,701
467.7
95.6
1993
51,779
484.4
106.9
1994
48,922
503.6
97.1
1995
48,975
523.6
93.5
1996
54,344
562.3
96.6
1997
58,108
567.8
102.3
1998
56,843
588.4
96.6
Part Four: Utah Energy Baseline
Page 4-5
-------
Overall, through the 1990s, residential electricity use in Utah increased in total and for the average
household, while natural gas increased in total but remained roughly constant for the average
household. These facts provide a benchmark for policy makers as they consider various GHG
emissions mitigation options across sectors.
B. Baseline Carbon Dioxide Emissions in the 1990s
Tables 4-9 and 4-10 present Utah residential sector energy-related C02 emissions by fuel. As Table
4-9 reveals, natural gas consumption accounts for approximately one-third of the sector's total C02
emissions with the remainder accounted for by electricity sales and losses. All other fuels, such as
coal, LPG, and heating oil have declined from 5.3 percent of total residential sector C02 emissions
at the beginning of the decade to about 3.0 percent by 1998. Electricity losses represent over twice
the amount of electricity sales. As a result, reducing electricity use is an important way to eliminate
or slow C02 emissions. For example, if residential sector electricity demand is reduced by one
Table 4-9. Utah Residential C02 Emissions (thousand Table 4-10. Utah Residential C02 Emissions (as a
tons) percent)
Natural
Gas
Electric
Sales
Electric
Losses
All
Other
Fuels
Total
1990
2,751
1,441
3,151
412
7,756
1991
3,158
1,513
3,295
397
8,364
1992
2,805
1,529
3,266
365
7,964
1993
3,257
1,604
3,388
291
8,539
1994
3,042
1,700
3,547
198
8,487
1995
3,031
1,710
3,563
241
8,546
1996
3,297
1,860
3,871
293
9,321
1997
3,524
1,921
3,989
226
9,661
1998
3,440
1,953
4,066
265
9,724
Natural
Electric
Electric All Other
Gas
Sales
Losses
Fuels
Total
1990
35.5%
18.6%
40.6%
5.3%
100.0%
1991
37.8%
18.1%
39.4%
4.7%
100.0%
1992
35.2%
19.2%
41.0%
4.6%
100.0%
1993
38.1%
18.8%
39.7%
3.4%
100.0%
1994
35.8%
20.0%
41.8%
2.3%
100.0%
1995
35.5%
20.0%
41.7%
2.8%
100.0%
1996
35.4%
20.0%
41.5%
3.1%
100.0%
1997
36.5%
19.9%
41.3%
2.3%
100.0%
1998
35.4%
20.1%
41.8%
2.7%
100.0%
quarter and results in a reduction of about 0.5
million tons C02, then the C02 emissions from
accompanying electricity losses are reduced by
over 1.0 million tons. The total reduction is over
1.5 million tons C02.
The annual growth of C02 emissions in the Utah
residential sector is shown in Table 4-11. While
growing with population overall, natural gas use
has fluctuated annually due to the variation in
weather patterns. Electricity demand, in contrast,
has consistently outpaced population growth in
recent years. All other fuels, primarily coal and
LPG, have been generally declining this decade.
The combined annual average growth rate of C02
4-11. Annual Growth in Utah Residential C02
All
Natural
Electric
Electric
Other
Gas
Sales
Losses
Fuels
Total
1991
14.8%
5.0%
4.5%
-3.7%
7.8%
1992
-11.2%
1.0%
-0.9%
-8.1%
-4.8%
1993
16.1%
4.9%
3.8%
-20.2%
7.2%
1994
-6.6%
6.0%
4.7%
-31.9%
-0.6%
1995
-0.4%
0.6%
0.5%
21.8%
0.7%
1996
8.8%
8.7%
8.6%
21.5%
9.1%
1997
6.9%
3.3%
3.3%
-22.7%
3.6%
1998
-2.4%
1.7%
1.9%
17.1%
0.7%
TOTAL
25.0%
35.6%
29.0%
-35.8%
25.4%
Page 4-6
Part Four: Utah Energy Baseline
-------
emissions from electricity sales and losses, which have been at 3.9 percent this decade, suggests
again that reducing residential electricity use is a key GHG mitigation strategy.
C. The Matrix of Residential Sector Energy by End Use
To better understand how energy is used in the residential sector, and the resulting C02 emissions,
a matrix of energy sources including electricity losses and end uses is presented in Tables 4-12 and
4-13. As evident, the major fuels are electricity and natural gas with minor contributions from fuel
oil and LPG. Highlighting end use by fuel, the table illustrates those areas which should be targeted
with mitigation measures to provide the most meaningful GHG reductions.
By fuel, electric sales and associated losses account for about 62 percent of total Utah residential
sector C02 emissions. Natural gas, which has a significantly lower carbon-to-Btu ratio than coal,
contributes over a third of total C02 emissions. By end use, as indicated in Table 4-13, roughly half
of all C02 emissions are accounted for by space and water heating. Combined, refrigeration and
Table 4-12. Utah Residential C02 Emissions in 1998 (in thousand tons)
Electric
Natural
All Other
Electricity
Losses
Gas
Fuels
Total
Space heating
211
439
2,133
242
3,025
Secondary heating
10
20
0
0
30
Central air conditioning
137
285
0
0
421
Room air conditioning
113
236
0
0
349
Water heating
252
524
1,170
4
1,950
Refrigerators
295
614
0
0
909
Lighting
227
472
0
0
698
Clothes washer
174
362
0
0
536
Range/oven
64
134
69
21
288
Clothes dryer
117
244
69
0
430
All other appliances
354
736
0
0
1,089
Total
1,953
4,066
3,440
266
9,724
Table 4-13. Utah Residential C02 Emissions in 1998 (as a percent)
Electric
Natural
All Other
Electricity
Losses
Gas
Fuels
Total
Space heating
2.2%
4.6%
21.9%
2.5%
31.1%
Secondary heating
0.1%
0.2%
0.3%
Central air conditioning
1.4%
2.9%
4.3%
Room air conditioning
1.2%
2.4%
3.6%
W ater heating
2.6%
5.4%
12.0%
20.1%
Refrigerators
3.0%
6.3%
9.3%
Lighting
2.3%
4.9%
7.2%
Clothes washers
1.8%
3.7%
5.5%
Range/ovens
0.7%
1.4%
0.7%
0.2%
3.0%
Clothes dryers
1.2%
2.5%
0.7%
4.4%
All other appliances
3.6%
7.6%
11.2%
Total
20.1%
41.8%
35.4%
2.7%
100.0%
Part Four: Utah Energy Baseline
Page 4-7
-------
lighting represent nearly 17 percent of all emissions. The balance is comprised mainly of clothes
washing and drying, and climate control (HVAC).
III. Utah Commercial Sector Energy Use and Carbon Dioxide Emissions
A. Overview of Aggregate Trends
As with the residential sector, the commercial sector consumes both electricity and natural gas, as
well as a limited quantities of other fuels. In comparison with the industrial sector, which produces
"goods" for the economy, the commercial sector
produces "services." As buildings are the primary
category of end-use consumption for providing these
services, this section identifies the many functions
buildings perform and evaluates them in terms of
their individual contributions to the production of
C02 emissions.
Total electricity consumption in the Utah com-
mercial sector is shown in Table 4-14. Also
included are data for total commercial sector
customers, which have grown from about 63,000 at
the beginning of the 1990s to 82,376 bythe decade's
end. Average electricity consumption per customer,
having stabilized at around 85,000 kWh for several years, has increased to over 90,000 kWh. This
sector shows the same trend as that of households in the residential sector, with increasing average
electricity per customer. The commercial sector has many components including retail and
wholesale trade, financial, real estate, service, and communication industries. Energy in this sector
is used in both large and small buildings ranging from 1,000 sq. ft. to over 100,000 sq, ft.
Natural gas use in the commercial sector is shown
in Table 4-15. While average residential demand for
natural gas varied somewhat within a range, average
commercial demand markedly increased in the
1990s. Total commercial sector natural gas use
began the decade at 16,220 mmcf and reached
30,955 mmcf by 1998, representing a total increase
of 90.8 percent, with an annual average growth rate
of about 11.4 percent. In contrast, natural gas
customers increased from 34,697 to 42,054 in the
decade, a total increase of 21.2 percent. The average
annual growth rate of customers (2.4 percent)
generally tracks the overall Utah population growth rate, yet the large increase in total natural gas
demand by the commercial sector has resulted in a significant increase in average customer con-
sumption.
Table 4-14. Utah Commercial Electricity Use
Consumption
Customers
kWh Per
(million kWh)
(thousands)
Customer
1990
5,389
62.8
85,752
1991
5,571
64.6
86,242
1992
5,850
66.4
88,167
1993
5,920
70.4
84,128
1994
6,341
70.8
89,525
1995
6,462
73.8
87,561
1996
6,717
75.8
88,649
1997
7,282
79.8
91,202
1998
7,433
82.4
90,237
Table 4-15. Utah Commercial Natural Gas Use
Consumption
Customers
mcf Per
(mmcf)
(thousands)
Customer
1990
16,220
34,697
467.5
1991
19,276
35,627
541.1
1992
16,584
36,145
458.8
1993
22,588
37,816
597.3
1994
26,501
39,183
676.3
1995
26,825
40,101
668.9
1996
29,543
40,107
736.6
1997
31,129
40,689
765.0
1998
30,955
42,054
736.1
Page 4-8
Part Four: Utah Energy Baseline
-------
Table 4-16. Utah Commercial C02 Emissions (in Table 4-17. Utah Commercial C02 Emissions (as a
thousand tons) percent)
All
All
Natural
Electric
Electric
Other
Natural
Electric
Electric
Other
Gas
Sales
Losses
Fuels
Total
Gas
Sales
Losses
Fuels
Total
1990
1,028
1,829
4,000
917
7,774
1990
13.2%
23.5%
51.5%
11.8%
100.0%
1991
1,204
1,891
4,116
813
8,023
1991
15.0%
23.6%
51.3%
10.1%
100.0%
1992
1,041
1,985
4,240
858
8,124
1992
12.8%
24.4%
52.2%
10.6%
100.0%
1993
1,421
2,009
4,244
580
8,253
1993
17.2%
24.3%
51.4%
7.0%
100.0%
1994
1,648
2,151
4,489
516
8,804
1994
18.7%
24.4%
51.0%
5.9%
100.0%
1995
1,660
2,193
4,568
507
8,929
1995
18.6%
24.6%
51.2%
5.7%
100.0%
1996
1,792
2,279
4,744
687
9,502
1996
18.9%
24.0%
49.9%
7.2%
100.0%
1997
1,888
2,472
5,134
393
9,887
1997
19.1%
25.0%
51.9%
4.0%
100.0%
1998
1,877
2,522
5,251
631
10,281
1998
18.3%
24.5%
51.1%
6.1%
100.0%
Table 4-18. Annual Growth in Utah C02 Emissions
B. Baseline Carbon Dioxide Emissions in the
1990s
Table 4-16 presents Utah commercial sector C02
emissions by fuel source. According to Table 4-
17, over three-fourths of total C02 emissions are
attributed to the consumption of electricity and
associated losses. Natural gas measures nearly 18
percent of the total, with all other fuels amounting
to about 7 percent, a fairly dramatic decline from
11 percent in 1990.
All
Natural
Electric
Electric
Other
Gas
Sales
Losses
Fuels
Total
1991
17.2%
3.4%
2.9%
-11.3%
3.2%
1992
-13.6%
5.0%
3.0%
5.5%
1.3%
1993
36.5%
1.2%
0.1%
-32.5%
1.6%
1994
16.0%
7.1%
5.8%
-11.0%
6.7%
1995
0.7%
1.9%
1.8%
-1.6%
1.4%
1996
8.0%
3.9%
3.8%
35.4%
6.4%
1997
5.3%
8.5%
8.2%
-42.8%
4.0%
1998
-0.6%
2.0%
2.3%
60.5%
4.0%
TOTAL
82.7%
37.9%
31.3%
-31.2%
32.3%
Similarly, reducing or slowing electricity sales is
missions in the commercial sector. For example, if
/hich in 1998 resulted in about 2,522 thousand tons of
30 thousand tons, then the CO, emissions from the
Table 4-19. Utah Commercial C02 Emissions in 1998 (in
thousand tons)
Electric
Electric
Natural
All Other
Sales
Losses
Gas
Fuels
Total
Space heating
107
223
1,054
379
1,763
Cooling
329
685
0
0
1,013
Ventilation
157
326
0
0
483
Water heating
45
95
503
126
769
Lighting
1,163
2,420
0
0
3,583
Cooking
18
38
191
0
248
Refrigeration
176
366
0
0
542
Office
equipment
323
672
0
0
995
Other
204
425
130
126
885
Total
2,522
5,251
1,877
631
10,281
an important way to reduce or slow C02
commercial sector electricity consumption,
C02, is reduced by 25 percent, or about (
accompanying electricity losses are reduced
by almost 1,300 thousand tons. Together,
electricity sales and associated losses
comprise over 75 percent of the total C02
emissions in the commercial sector. As
compared with the 62 percent found in the
residential sector, commercial sector elec-
tricity consumption represents an even
larger proportion of total GHG emissions.
The annual growth rate of C02 emissions in
the Utah commercial sector is shown in
Table 4-18. As with the residential sector,
natural gas use follows population trends
Part Four: Utah Energy Baseline
Page 4-9
-------
with some variation due to weather Table 4-20. Utah Commercial C02 Emissions in 1998 (as a
patterns. Electricity demand, in contrast,
has grown faster than population in
recent years. With the Utah economy
expanding at a record pace throughout
the 1990s, electricity sales and their
associated losses have even surpassed
the overall growth in the Utah economy.
Notably, electricity sales and associated
losses have averaged 4.2 percent per
year through the 1990s. All other fuels,
primarily coal and LPG, have generally
declined during the 1990s.
percent)
All
Electric
Electric
Natural
Other
Sales
Losses
Gas
Fuels
Total
Space heating
1.0%
2.2%
10.2%
3.7%
17.1%
Cooling
3.2%
6.7%
0.0%
0.0%
9.9%
Ventilation
1.5%
3.2%
0.0%
0.0%
4.7%
Water heating
0.4%
0.9%
4.9%
1.2%
7.5%
Lighting
11.3%
23.5%
0.0%
0.0%
34.8%
Cooking
0.2%
0.4%
1.9%
0.0%
2.4%
Refrigeration
1.7%
3.6%
0.0%
0.0%
5.3%
Office equipment
3.1%
6.5%
0.0%
0.0%
9.7%
Other
2.0%
4.1%
1.3%
1.2%
8.6%
Total
24.5%
51.1%
18.3%
6.1%
100.0%
The I tali C ommercial Sector and Tourism
The Governor's Ol'lice of Planning and
Mudgel ((iOl'M) notes llial the 2002 Winter
Olympics lias accelerated a number of projects
on llie drawing board llial would lia\e
occurred without llie Olympics, l or example
hotel construction, greatly speared by expected
high occupancy rales, would ha\e occurred
o\er a 10-year time period instead ol" the
current 5-year time period. The (iOl'M esti-
mates that 25 percent ofholel construction has
been accelerated so that the facilities w ill be in
place prior lo the games. In addition to hotels,
a \ariely ol'other inl'raslnicliire investments
will be affected by the Winter Olympics,
including public facilities, such as the Salt
Lake International Airport, \arions highways
and transit systems, and pri\ ale facilities, such
as ski resorts. Some projects, such as the
Winter Olympic \ennes and access roads are
built speciIleally for the (iames. In other
cases, only the timing of the inl'raslnicliire
investment is affected. The end result is more
economic activity from lWh lo 2002 than
would otherwise ha\e occurred. This imest-
menl in inl'raslnicliire. particularly trans-
portation inl'raslnicliire. has implications for
Utah's (iIKi emissions. Tonrism-relaled
pollution has already become a problem in
some areas, l or example, increases in smog
from \ chicles ha\e forced llie National l'ark
Service lo close some areas lo automobile
louring. Similarly, high traffic \oliimes in
Summit County. I'lali home lo world-
renowned recreational facilities ha\e
resulted in increased air pollution llial may
e\ enlually jeopardize the allracli\ eness of the
area as a resort destination.
In spile of slower growth in tourism spending
and \isilalion in ll>l)~ and ll>l)S. The (iOl'M
forecasts thai tourism will grow considerably
as I'lali receives increased awareness due lo
llie 2002 Olympic Winter (iames. foreign
exchange rales, airfares and direct inler-
nalional llighls lo Salt Lake International
Airport are oilier major factors lo consider.
National lra\el trends point toward increasing
interest in ecolourism. heritage tourism, and
sol'l-ad\enlure activities. I'lali is
well-posilioned lo attract those \isilors
seeking a higher quality, more unique
experience and who are willing lo pay more
and slay longer. My focusing on quality o\er
quantity, tourism can provide higher quality
earnings, with fewer of llie challenges often
associated w illi "w indshield" tourism.
Page 4-10
Part Four: Utah Energy Baseline
-------
C. The Matrix of Commercial Energy Use and C02 Emissions
For the year 1998, Table 4-19 describes how energy is used in the commercial sector and,
correspondingly, how this consumption translates into GHG emissions by energy source and end use.
The matrix, according to Table 4-20, shows electricity and natural gas as the primary energy sources
consumed in the state, representing 75 percent (including losses) and 18 percent of GHG emissions
respectively. Lighting accounts for over a third ofthese emissions, followed by space heating (17.9
percent), cooling (9.8 percent) and office equipment (9.6 percent). The balance of emissions is found
in a wide array of other end uses.
IV. Utah Industrial Sector and C02 Emissions.
A. Overview of Aggregate Trends
The Utah industrial sector began the 1980s with annual consumption of almost 218 trillion Btu. In
reaction to the steep increase in energy prices in the late 1970s, as well as local Utah conditions, the
industrial sector energy demand fell considerably. For example, Geneva Steel in Provo shutdown
for several years in the mid-1980s. By 1987, Utah industrial energy demand fell to less than 150
trillion Btu, a decline of almost one third since the beginning of the decade. Since 1987, however,
Utah industrial energy demand has recovered with sustained growth in every year through 1998. At
the end of the 1990s, Utah industrial energy demand was above 250 trillion Btu.
Table 4-21 depicts these trends, including energy
. . j a a 1 • j a • 1 ¦ Table 4-21. Utah Industrial Energy Use
intensity measured as total industrial energy use m
million Btu per dollar of industrial Gross State
Product (GSP). GSP is a measure of the value of
output at the state level and is conceptually similar to
Gross Domestic Product (GDP).
B. Baseline Utah Industrial Sector C02
Emissions in the 1990s
The Utah industrial sector presents a more
complicated picture than either the residential or
commercial sector. In addition to natural gas and
electricity, substantial amounts of coal are also
consumed. Table 4-22 presents Utah industrial
sector C02 emissions by fuel. Nearly half of these
emissions are associated with electricity sales and
losses. Natural gas and coal each account for about a
quarter, followed by distillate fuel and all other fuels.
Table 4-24 shows a large degree of year-to-year
variation in energy use by fuel.
Industrial
Industrial
Industrial
Energy Use
GSP
Energy Use
(Trillion Btu)
(million
per GSP dollar
dollars)
(million)
1980
218.5
5,528
39.5
1981
209.4
5,669
36.9
1982
187.3
5,448
34.4
1983
196.7
5,619
35.0
1984
198.1
6,433
30.8
1985
182.9
7,052
25.9
1986
158.1
6,706
23.6
1987
147.6
6,706
22.0
1988
197.2
7,321
26.9
1989
208.7
7,292
28.6
1990
213.2
7,792
27.4
1991
218.6
8,279
26.4
1992
211.9
8,347
25.4
1993
214.7
8,850
24.3
1994
215.4
9,845
21.9
1995
245.3
10,652
23.0
1996
251.8
11,364
22.2
1997
249.7
11,705
21.3
1998
254.7
12,056
21.1
Part Four: Utah Energy Baseline
Page 4-11
-------
Table 4-22. Utah Industrial C02 Emissions (in thousand tons)
Natural
Distillate
All
Other
Electric
Electric
Coal
Gas
Fuel
Fuels
Sales
Losses
Total
1990
4,477
3,499
700
346
1,957
4,280
15,258
1991
4,521
3,550
880
236
1,994
4,340
15,521
1992
3,925
3,355
906
272
2,108
4,502
15,069
1993
3,981
3,449
850
350
2,111
4,460
15,202
1994
4,313
3,104
831
440
2,205
4,601
15,495
1995
3,983
4,292
745
598
2,361
4,918
16,897
1996
3,827
4,208
853
762
2,599
5,410
17,658
1997
4,140
4,163
1,115
801
2,521
5,236
17,982
1998
4,185
4,416
1,160
833
2,549
5,306
18,448
Table 4-23. Utah Industrial C02 Emissions (as a percent)
Coal
Natural
Gas
Distillate
Fuel
All Other
Fuels
Electric
Sales
Electric
Losses
Total
1990
29.3%
22.9%
4.6%
2.3%
12.8%
28.0%
100.0%
1991
29.1%
22.9%
5.7%
1.5%
12.8%
28.0%
100.0%
1992
26.0%
22.3%
6.0%
1.8%
14.0%
29.9%
100.0%
1993
26.2%
22.7%
5.6%
2.3%
13.9%
29.3%
100.0%
1994
27.8%
20.0%
5.4%
2.8%
14.2%
29.7%
100.0%
1995
23.6%
25.4%
4.4%
3.5%
14.0%
29.1%
100.0%
1996
21.7%
23.8%
4.8%
4.3%
14.7%
30.6%
100.0%
1997
23.0%
23.1%
6.2%
4.5%
14.0%
29.1%
100.0%
1998
22.7%
23.9%
6.3%
4.5%
13.8%
28.8%
100.0%
Page 4-12
Part Four: Utah Energy Baseline
-------
Table 4-25. Utah Industrial C02 Emissions in 1998 (in thousand tons)
Coal
Natural
Gas
Distillate
Fuel
All Other
Fuels
Electric
Sales
Electric
Losses
Total
Process
418
530
70
42
1,657
3,449
6,165
Process heating
3,766
1,855
777
567
204
424
7,593
Process cooling
0
0
0
0
178
371
550
Space heating
0
1,501
139
175
25
53
1,894
Space cooling
0
0
0
0
127
265
393
Lighting
0
0
0
0
153
318
471
Ventilation
0
0
0
0
127
265
393
W ater heating
0
353
116
42
25
53
589
Other
0
177
58
8
51
106
400
Total
4,185
4,416
1,160
833
2,549
5,306
18,448
As electricity losses are more than twice the amount of electricity sales, reducing or slowing sales
is an important way to reduce or slow C02 emissions. For example, if industrial sector electricity
consumption, which in 1998 resulted in about 2,549 thousand tons of C02, is reduced 25 percent,
or by about 637 thousand tons, then the C02 emissions from the accompanying electricity losses are
reduced by about 1,327 thousand tons of C02. Together, electricity sales and their associated losses
comprise about 43 percent of the total C02 emissions in the Utah industrial sector. This should be
compared to the 62 percent found in the Utah residential sector and the 75 percent in the Utah
commercial sector.
C. The Matrix of Industrial Energy Use and C02 Emissions
To understand how energy is used in the industrial sector, and the associated level of C02 emissions,
a matrix of industrial energy sources and end uses was developed. The matrix for the Utah industrial
sector in 1998 is shown in Table 4-25, with percentages shown in Table 4-26.
Table 4-24. Annual Growth in Utah Industrial C02 Emissions
Coal
Natural
Gas
Distillate
Fuel
All Other
Fuels
Electric
Sales
Electric
Losses
Total
1991
1.0%
1.5%
25.8%
-31.9%
1.9%
1.4%
1.7%
1992
-13.2%
-5.5%
2.9%
15.5%
5.7%
3.7%
-2.9%
1993
1.4%
2.8%
-6.1%
28.6%
0.2%
-0.9%
0.9%
1994
8.3%
-10.0%
-2.2%
25.7%
4.5%
3.2%
1.9%
1995
-7.6%
38.3%
-10.4%
35.7%
7.1%
6.9%
9.1%
1996
-3.9%
-2.0%
14.4%
27.5%
10.1%
10.0%
4.5%
1997
8.2%
-1.1%
30.8%
5.9%
-3.0%
-3.2%
1.8%
1998
1.1%
6.1%
4.0%
3.3%
1.1%
1.3%
2.6%
TOTAL
-6.5%
26.2%
65.8%
140.9%
30.3%
24.0%
20.9%
Part Four: Utah Energy Baseline
Page 4-13
-------
V. Utah Transportation Sector and C02 Emissions
A. Overview of Aggregate Trends
Although many fuels are used in the Utah transportation sector, the largest category of consumption
is motor gasoline for automobiles. Other significant fuels include diesel fuel, which is used for both
truck and rail transportation, as well as jet fuel used for air transportation.
Table 4-27 indicates that, between 1990 and 1998, Utah gasoline consumption increased a total of
37.2 percent, or about 4.7 percent ayear, from 690.1 to 946.6 million gallons. Average consumption
per automobile, during the same decade, increased from 887 to 1,091 gallons per automobile per
year, representing a total change of 23 percent, or about 2.9 percent per year.
Page 4-14
Part Four: Utah Energy Baseline
-------
Closely related to the growth in motor gasoline demand is the growth in the number of automobiles
and vehicle-miles traveled. Table 4-28 displays the number of Utah registered automobiles,
automobile vehicle-miles traveled (VMTs), and average vehicle-miles traveled per automobile.
Between 1990 and 1998, Utah automobiles have increased a total of 11.6 percent, or about 1.4
percent a year, from 777,906 to 867,828. Yet over the same period, automobile VMTs dramatically
increased by a total of 45.2 percent, or about 5.7 percent a year, from 9.8 to 14.3 billion miles.
Average miles per automobile is one of many measures of transportation sector intensity of use. This
Table 4-26. Utah Industrial C02 Emissions in 1998 (as a percent)
Coal
Natural Distillate All Other
Gas Fuel Fuels
Electric
Sales
Electric
Losses
Total
Process
2.3%
2.9%
0.4%
0.2%
9.0%
18.7%
33.4%
Process heating
20.4%
10.1%
4.2%
3.1%
1.1%
2.3%
41.2%
Process cooling
1.0%
2.0%
3.0%
Space heating
8.1%
0.8%
0.9%
0.1%
0.3%
10.3%
Space cooling
0.7%
1.4%
2.1%
Lighting
0.8%
1.7%
2.6%
Ventilation
0.7%
1.4%
2.1%
W ater heating
1.9%
0.6%
0.2%
0.1%
0.3%
3.2%
Other
1.0%
0.3%
0.3%
0.6%
2.2%
Total
22.7%
23.9%
6.3%
4.5%
13.8%
28.8%
100.0%
amount increased during this time period 30.2 percent, or about 3.8 percent a year, from 12,614 to
16,421 miles per automobile per year. Finally, miles per gallon (MPG) is the primary measure of
transportation sector fuel efficiency. During this decade, MPG remained constant at about 22 miles
per gallon.
B. Baseline UtahC02 Emissions in the 1990s
The Utah transportation sector primarily uses motor gasoline, diesel fuel, and jet fuel for highway,
railroad, and airline energy. Table 4-29 presents Utah transportation sector energy-related C02
emissions.
Table 4-27. Utah Gasoline Consumption
Gasoline
Average
Consumption
Consumption
(thousand
per Automobile
gallons)
(gallons)
1990
690,060
887
1991
718,284
942
1992
740,292
998
1993
779,898
1,004
1994
802,074
1,007
1995
857,976
1,065
1996
874,356
1,078
1997
910,140
1,070
1998
946,554
1,091
Table 4-28. Utah Automobiles and Miles Traveled
Automobiles
Vehicle-Miles
Traveled
(millions)
Average Annual
Miles per
Automobile
1990
777,906
9,813
12,614
1991
762,179
10,312
13,530
1992
741,713
10,926
14,730
1993
776,484
11,428
14,717
1994
796,877
12,112
15,200
1995
805,609
12,583
15,620
1996
811,383
13,091
16,134
1997
850,812
13,697
16,099
1998
867,828
14,251
16,421
Page 4-14
Part Four: Utah Energy Baseline
-------
1-15 Reconstruction
In sprint* lW-. llie I'lah Department of
Transportation (I'DOT) began a recon-
struction project ol'l-l 5. The goal of this four-
and-a-half year project is to remo\e the Salt
Lake section ol' 1-15. uliicli had outlived its
life sp;in by ;iboul 20 ye;irs. anil tlien to
reconstruct a highway llial would meet the
expected highway demand in Suit Lake lor
the next 50 years.
The scale ol'llie project is iinpressi\ e w iill an
estiinaletl cost ol'S 1,5l) billion. The length ol'
the freeway is roughly 1~ miles ;ind I'DOT
estimates that it will use more than 5 million
cubic yards ol' fill material (about 360.000
dump truck loads) during 1-15 reconstruction.
The project includes the replacement ol'more
than 144 bridges and frontage road improve-
ments. The "Desitin-Muild" approach to con-
struction is also noteworthy. It is the largest
project e\er attempted using this method,
w here the same contracting team both designs
and builds the project. This method allow s the
coniraclinti team lo construct some sections
w hile other sections are still in the final design
phase.
Traffic capacity on 1-15 will be bolstered by
an increase in lanes lo a total oflweke — six
in each direction — including new. high-
occupancy \ehicle (NOV) lanes. Ilowe\er.
impro\ ed freeway capacity w ill likely increase
(iIKi emissions as more people mo\e into
suburban areas and as across-\ alley commutes
become easier lo make.
Table 4-29. Utah Transportation C02 Emissions (in thousand tons)
Distillate
Fuel
Motor
Gasoline
Jet Fuel
All Other
Fuels
Total
1990
2,444
6,704
2,364
181
11,693
1991
2,412
6,979
2,649
155
12,194
1992
2,544
7,193
2,510
189
12,435
1993
2,606
7,577
2,470
261
12,915
1994
2,774
7,793
2,359
271
13,197
1995
3,244
8,336
2,533
257
14,370
1996
3,456
8,495
2,822
300
15,072
1997
3,793
8,843
2,810
259
15,704
1998
3,717
9,196
2,852
251
16,016
Motor gasoline, as a share of total Utah transportation sector energy use, has remained constant
throughout the decade of the 1990s at between 56 and 59 percent. While jet fuel has declined from
almost 22 percent at the beginning of the decade to about 18 percent by 1998, diesel fuel use has
noticeably increased. Diesel fuels have almost reversed the jet fuel pattern and grown from about
20 percent to almost 24 percent of Utah transportation-related energy use. Unlike the residential,
commercial and industrial sectors, very little electricity is used by the transportation sector. The
annual growth in Utah transportation energy use is given in Table 4-31. Overall, the sector has
shown strong growth at over 4 percent a year this decade. Not only are transportation-related motor
gasoline and diesel fuel significant contributors to GHG emissions, both have demonstrated
sustained growth. In some cases, this sustained growth has been well above 4 percent.
Part Four: Utah Energy Baseline
Page 4-15
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Table 4-30. Utah Transportation C02 Emissions (as a
percent)
Table 4-31. Annual Growth in Utah Transportation
C02 Emissions
Distillate
Motor
All
Fuel
Gasoline
Jet Fuel
Other
Fuels
Total
1990
20.9%
57.3%
20.2%
1.5%
100.0%
1991
19.8%
57.2%
21.7%
1.3%
100.0%
1992
20.5%
57.8%
20.2%
1.5%
100.0%
1993
20.2%
58.7%
19.1%
2.0%
100.0%
1994
21.0%
59.1%
17.9%
2.1%
100.0%
1995
22.6%
58.0%
17.6%
1.8%
100.0%
1996
22.9%
56.4%
18.7%
2.0%
100.0%
1997
24.2%
56.3%
17.9%
1.6%
100.0%
1998
23.2%
57.4%
17.8%
1.6%
100.0%
All
Distillate
Motor
Other
Fuel
Gasoline
Jet Fuel
Fuels
Total
1991
-1.3%
4.1%
12.1%
-14.1%
4.3%
1992
5.5%
3.1%
-5.2%
21.7%
2.0%
1993
2.5%
5.3%
-1.6%
38.1%
3.9%
1994
6.4%
2.8%
-4.5%
3.9%
2.2%
1995
17.0%
7.0%
7.4%
-5.2%
8.9%
1996
6.5%
1.9%
11.4%
16.8%
4.9%
1997
9.8%
4.1%
-0.4%
-13.6%
4.2%
1998
-2.0%
4.0%
1.5%
-3.3%
2.0%
TOTAL
52.1%
37.2%
20.6%
44.7%
37.0%
C. The Matrix of Transportation Energy Use and C02 Emissions
To understand how energy is used in the transportation sector, and the resulting C02 emissions, a
matrix of transportation energy sources and end uses was developed. The matrix for the Utah
transportation sector in 1998 is shown in Table 4-32. The transportation sector relies on motor
gasoline diesel fuel, and jet fuel, with smaller amounts of other fuels. Electricity is not used and
natural gas plays a small role. Most of the natural gas used in the transportation section is used as
pipeline fuel, although vehicle conversion to natural gas shows promise in the future.
Table 4-32. Utah Transportation C02 Emissions in 1998 (in thousand tons)
Gasoline
Diesel
Jet fuel
All Other
Fuels
Total
HIGHWAY
8,912
2,738
1
11,651
Automobiles
5,106
88
1
5,194
Motorcycles
15
15
Buses
19
100
1
120
Trucks
3,772
2,551
6,322
Light trucks
3,413
152
3,565
Other trucks
358
2,399
2,757
OFF-HIGHWAY
90
718
808
Construction
21
435
456
Agriculture
69
284
353
NON-HIGHWAY
194
521
2,852
249
3,817
Air
21
2,852
2,873
Water
174
174
Freight
Recreational
174
174
Rail
521
521
Freight
503
503
Passenger
19
19
Total
9,196
3,717
2,852
251
16,016
Page 4-16
Part Four: Utah Energy Baseline
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Table 4-33. Utah Transportation C02 Emissions in 1998 (as a percent)
Gasoline
Diesel
Jet fuel
All Other
Fuels
Total
HIGHWAY
55.6%
17.1%
0.1%
72.7%
Automobiles
31.9%
0.5%
0.1%
32.4%
Motorcycles
0.1%
0.1%
Buses
0.1%
0.6%
0.1%
0.8%
Trucks
23.5%
15.9%
39.5%
Light trucks
21.3%
0.9%
22.3%
Other trucks
2.2%
15.0%
17.2%
OFF-HIGHWAY
0.6%
4.5%
5.0%
Construction
0.1%
2.7%
2.8%
Agriculture
0.4%
1.8%
2.2%
NON-HIGHWAY
1.2%
3.3%
17.8%
99.6%
23.8%
Air
0.1%
17.8%
17.9%
Water
1.1%
1.1%
Freight
0.0%
Recreational
1.1%
1.1%
Rail
3.3%
3.3%
Freight
3.1%
3.1%
Passenger
0.1%
0.1%
Total
57.4%
23.2%
17.8%
1.6%
100.0%
By category, highway transportation accounts for nearly three-fourths of total C02 emissions,
followed by the non-highway (24 percent) and off-highway (5 percent) categories. Within the
highway category, trucks account for the largest share at nearly 40 percent compared with
automobiles (32 percent). Emissions due to off-highway uses, including agriculture and construction,
are marginal as well. Finally, in the non-highway sector, air transportation is the dominant source
of emissions with minor contributions from rail and recreational transportation.
VI. Utah Electric Utility Sector and C02 Emissions
A. Overview of Aggregate Trends
Approximately 95 percent of total electric power in Utah is generated by coal-fired plants. Of this
total, some 90 percent is generated from only 5 large coal-fired plants operating at high capacity
factors (85-90 percent). When examining GHG emissions from a fuel input perspective, as opposed
to end-use consumption, it is clear that these five plants account for the majority of C02 emissions.
Fuel consumption at Utah electric power plants is shown in Table 4-34. Coal consumption by Utah
electric utilities grew a total of 7.2 percent in the decade of the 1990s, reflecting an annual average
growth rate of 0.9 percent. Natural gas is used by Utah electric utilities as a seasonal peaking fuel,
and its growth is much more difficult to evaluate since demand patterns are more erratic. In 1991,
natural gas demand was about 5.2 billion cubic feet (Bcf). Over the next several years it shot
upwards to near 9.0 Bcf, only to return to 5.3 Bcf in 1998.
Part Four: Utah Energy Baseline
Page 4-1 7
-------
Light fuel oil is the third fuel used at Utah electric utilities and is used as a start-up fuel for a large
coal-fired power plant. Distillate fuel oil in 1998 was at 63 percent of its 1990 level representing
an average annual decline rate of 4.6 percent.
B. Baseline Utah Electric Utility Sector C02 Emissions in the 1990s
The Utah electric utility sector produces about 60 percent of the state's total C02 emissions. While
coal-fired steam generation fluctuates around 94-95 percent of total electric power generation, coal
consumption by Utah's electric utilities results in 99 percent of Utah's electric utility C02 emissions.
Natural gas and distillate fuel oil contribute small amounts
C. Electric Utility Energy Use and C02 Emissions
Unlike the previous energy-consuming sectors, the electric utility sector is strictly a supply resource;
therefore, there are no end uses associated with electric power generation per se. Nevertheless, it is
important to understand the fundamentals of the
industry in order to better appreciate the scale and
scope of the industry's contribution to C02
emissions. The following, therefore, includes a brief
overview of the industry's structure, operation, and
performance.
As noted, Utah's coal-fired generation dominates
production (approximately 95 percent), with
approximately 4 percent contributed by hydroelectric
resources. The remainder is composed of natural gas,
other fossil fuels, and geothermal sources.
Of the coal production, PacifiCorp-owned Utah Power (UP) owns and operates roughly 52 percent
of all coal-fired facilities in the state. Since January 1998, the capacity factor (a measure of output
ability) at UP's plants has been high, though four out of seven units to date are registering declines
over 1997 year averages.
The Intermountain Power Project (IPP), a 1,660 MW coal-fired facility, continues to account for a
substantial share of coal-fired generation. Positioning itself for increased competition in California,
the state with which it has a long-term power contract, IPP has cut
cost dramatically, including 76 staff positions in 1997 alone. With
only 472 employees, the IPP facility has recently garnered industry
recognition for its efficient operations. A recent industry article on
the nation's top 100 facilities ranked IPP as 68th in generation, 43rd
in cost of operation, 19th in heat rate (Btu/kWh), and 2nd in capacity
factor. Revised estimates show gross generation (including auxiliary
power) having increased from 11,365.1 GWh in 1996 to 13,482.4
GWh in 1997. Year-end calculations put IPP generation at 13,624
GWh, a potentially record setting year.
Table 4-34. Electric Utility Fuel Consumption
Coal
Natural
Distillate
(Short Tons)
(bcf)
(Barrels)
1990
14,053,000
0.843
84,000
1991
13,472,000
5.190
82,000
1992
13,136,000
6.576
62,000
1993
13,343,000
6.305
55,000
1994
13,839,000
8.900
53,000
1995
12,550,000
8.707
61,000
1996
12,728,000
3.428
55,000
1997
14,780,000
4.079
52,000
1998
14,545,000
5.268
53,000
Table 4-35. Utah Coal-fired
Power Plant Capacity
Megawatts
(MW)
IPP
1,640
Hunter
1,415
Huntington
896
Bonanza
400
Carbon
189
Non-coal
771
State total
5,311
Page 4-18
Part Four: Utah Energy Baseline
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Table 4-36. Utah Electric Utility C02 Emissions
(in thousand tons)
Coal
Natural
Gas
Distillate
Fuel
Total
1990
32,852
49
39
32,940
1991
31,494
322
38
31,854
1992
30,708
411
29
31,148
1993
31,192
390
26
31,608
1994
32,352
541
25
32,917
1995
29,338
535
28
29,901
1996
29,755
204
26
29,984
1997
34,552
247
24
34,822
1998
34,002
360
25
34,387
Table 4-37. Utah Electric Utility C02 Emissions
(as a percent)
Natural
Distillate
Coal
Gas
Fuel
Total
1990
99.7%
0.1%
0.1%
100.0%
1991
98.9%
1.0%
0.1%
100.0%
1992
98.6%
1.3%
0.1%
100.0%
1993
98.7%
1.2%
0.1%
100.0%
1994
98.3%
1.6%
0.1%
100.0%
1995
98.1%
1.8%
0.1%
100.0%
1996
99.2%
0.7%
0.1%
100.0%
1997
99.2%
0.7%
0.1%
100.0%
1998
98.9%
1.0%
0.1%
100.0%
Composed of six members, the Utah Municipal
Power Agency (UMPA) generated 859,979 MWh through June 1998, a 3.14 percent increase over
the comparable period in 1997. For its non-members, including customers on the western grid, sales
increased sharply from 32,211 GWh in 1997 to 169,674 GWh in 1998. Peak demand also increased
by 5.27 percent over the year.
UMPA provides its members with electricity from several sources. Its 3.75 percent share in Deseret
Generation and Transmission's Bonanza Unit 1 produced 259,304,4 lOkWh in FY 98, a 2.4 percent
increase over last year. Overall, the Bonanza facility, ^ L1 ,, „„ A . TT. , .
J J Table 4-38. Annual Growth in Utah Electric
coal-fired unit, accounted for 28.5 percent of utility co2 Emissions.
UMPA's energy sources. In addition, through a 6.5
percent share in UP's Hunter I coal-fired unit, UMPA
produced 140,878,000 kWh from 27 MW, an 11.4
percent increase over the 1997 level. Hunter 1
accounts for 15.5 percent of UMPA's total sources.
By far, the largest share of UMPA power (42.3
percent) is purchased from the Colorado River
Storage Project (CRSP), which is operated by the
Western Area Power Administration (WAPA). From
CRSP's 93.57 MW of maximum available capacity,
the UMPA purchased 3 84,927,456 kWh, an 8 percent
increase over 1997 levels. The balance of UMPA's purchases include smaller shares of several plants
including the Bonnett plant (geothermal), several hydroelectric facilities, the Provo Power Plant, the
Deer Creek plant, and several PacifiCorp contracts.
Utah Associated Municipal Power Systems (UAMPS) logged 3,350,651 MWh in total system sales
(including purchased power contracts), a 10.4 percent increase over the 1997 amount. Sales to
members increased by 6 percent over the year, though off-system sales plummeted by 46 percent.
Overall, UAMPS energy sales increased by 1.9 percent from 2,273,323 MWh in 1997 to 2,316,397
in 1988. Increased sales are largely attributed to demand from Idaho Falls, a new UAMPS member.
Recent estimates indicate that Idaho Falls has 21,725 customers, requiring 631,908,602 kWh with
a peak demand of 138,446 kW.
Coal
Natural
Gas
Distillate
Fuel
Total
1991
-4.1%
556.5%
-2.4%
-3.3%
1992
-2.5%
27.5%
-24.4%
-2.2%
1993
1.6%
-5.1%
-11.3%
1.5%
1994
3.7%
38.6%
-3.6%
4.1%
1995
-9.3%
-1.1%
15.1%
-9.2%
1996
1.4%
-61.9%
-9.8%
-0.3%
1997
16.1%
21.2%
-5.5%
16.1%
1998
-1.6%
45.8%
1.9%
-1.3%
TOTAL
3.5
11.6
-36.9
4.4
Part Four: Utah Energy Baseline
Page 4-19
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With generation from its 430 MW coal-fired plant, supplemented by federal power contracts and a
25.1 percent share in PacifiCorp's Hunter II facility, Deseret Generation & Transmission serves
38,432 residential-farm and non-farm customers in six member districts throughout Utah and
neighboring states. Total 1997 sales reached 3,849,797 MWh with a slight shift from member to
non-member sales. Six new industrial customers have been added to the DG&T system, leading
analysts to project a 5.5 percent increase in 1998 for total sales of 4,052,415 MWh in 1998.
Improvements in operations of the Bonanza coal-fired plant has boosted DG&T's competitiveness
in recent years. According to DG&T plant availability, which includes both planned and unplanned
outages, increased to 94.8 percent in 1997 and is projected to reach 97.8 percent in 1998.
Deregulation
For the past several years, electric industry analysts have watched and waited for federal and state
actions on deregulation. While the precise effect of deregulation is unknown at this time, an
important result of deregulation should be the continued demand in California for IPP electric power
exports. Should Utah electric power exports remained at or near the current level of 13,000 million
kWh per year, Utah in-state consumption of electric power will need to be met by increased imports
from the Pacific Northwest. These imports will be generated by a mix of fuels but will have a large
hydro-power component.
VII. Assessment of Potential Energy Savings
Encouraging energy efficiency in all sectors of the Utah economy is of paramount important
importance in reducing GHG emissions. As approximately 85 percent of Utah's total GHG
emissions are linked to fossil fuel consumption, the prime areas for reduction include the electric
utility sector and the transportation sector. In the electricity sector, opportunities exist in both supply
and demand, the former including electric generation technologies, including fuel substitution, and
the latter including demand-side management strategies. In the transportation sector, a wide range
If strategies exist for improving both the technical performance of transportation modes, expanding
the range of modes used, and in fuel substitution as well.
The non-fossil sector, which accounts for the remaining 15 percent of carbon emissions (in C02
equivalent measures) covers a diverse set of economic sectors. Most of these sectors involve
industrial productivity for which mitigation strategies must be targeted at the level of the industrial
processes. Other non-fossil strategies relate to the recovery of potentially fugitive emissions in the
public works (waste management) sector and in industry.
Residential Sector
As compared with Utah's other energy consuming sectors, the options for mitigation in the
residential sector are relatively restricted. While households may elect to purchase supply-side
technologies such as solar or micro turbines, the capital costs are frequently prohibitive thus forcing
most residential energy customers to rely instead on less costly demand-side management and energy
efficiency practices. While new federal standards for appliances may be instituted, it is likely that
fuel substitution will remain a key mitigation strategy as long as sufficient natural gas pipelines and
Page 4-20
Part Four: Utah Energy Baseline
-------
supporting distribution infrastructure are in place. Furthermore, it is widely expected that
competitive markets for electricity will include additional energy efficiency opportunities.
Commercial Sector
The commercial sector lends itself to a wide variety of options for GHG emissions reduction
strategies. As with the residential sector, numerous opportunities exist for energy efficiency and
demand-side management. In addition to building shell improvements, fuel substitution is also a
preferred strategy. On the supply side, this sector can readily exploit district energy and cogeneration
options. As compared with the residential sector, the commercial focus on profits compels energy
customers in this sector to seek more cost-effective options.
Industrial Sector
The industrial sector accounts for a significant share of total GHG emissions. As with the
commercial sector, a wide array of both supply and demand-side management mitigation strategies
are available to this sector. In Utah, industrial customers have benefitted from many utility-sponsored
energy-efficiency programs. Large-scale cogeneration options remain an attractive option and
numerous energy-efficiency improvements are also available. In competitive electricity markets,
industrial customers stand to benefit greatly from power marketing programs that will likely include
energy-efficiency incentives.
Transportation Sector
It is evident from the statistics presented that the transportation sector is a major source of GHG
emissions in Utah. A wide variety of mitigation measures is available and, for this research,
generally fall into one of two categories: improvements to vehicle performance and infrastructure
improvements. Vehicle performance issues are typically addressed at the Federal level through, for
example, CAFE standards. At the state level, gasoline taxes may be applied to induce shifts in
demand. Infrastructure improvements range from mass transit to high-occupancy vehicles (HOV)
lanes.
Electric Utility Sector
Electric power generation in Utah is characterized by a high degree of reliance upon coal-fired
facilities. Because of the high capital costs of electric power facilities, it is unlikely that either large-
scale facilities using alternative fuels or renewable resources will be substituted for the currently
existing and depreciated assets. Instead, it is far more realistic that, over the short and medium term,
co-firing of natural gas will be used. Over the next few decades, combined-cycle facilities and
generators with higher heat rates should result in higher efficiencies and, in consequence, lower
GHG emissions.
The Non-Fossil Sector
As noted, the non-fossil sector accounts for roughly 15 percent of GHG emissions. Industrial
processes (limestone, lime, and cement) account for a relatively small fraction of the total.
Emissions in this category are linked to overall industrial productivity and construction activity in
the state; however, opportunities for reduction are rather limited due to the challenges of finding
Part Four: Utah Energy Baseline
Page 4-21
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Deregulation and (.itchhouse (.as Kmissions
Many of its proponents argue thai dereg-
ulation is lli^ key lo resoking a host of
en\ ironmenlal problems associated \\ ilh
power generation. In theory. deregulation
should promote ihe introduction ol' new
technologies, holli supply anil end-use. thai
will contribute greatly lo llie rednclion ol'C'O.
emissions. An additional henelll. associated
w ilh holli w holesale anil retail deregulation. is
llie prospeel of exporting larger amoimls of
power lo consumers throughout llie wesl.
While increased exports could result in greater
emissions within Utah's borders, those
importing I'tali power will likely receive a
considerable en\ ironmenlal benefit: power
generated by coal sources which are amonu
the world's cleanest and highest in Mlu. In
many instances, imported Utah power could
"back out" generation from dirtier, lower Mlu
coals. Currently it is uncerlain w helher or not
a deregulated market will allow lor Utah's
coal-fired power plants lo produce more
electricity for export. At issue is whether or
not the relative marginal costs of power
ueneralion will operate in fa\or of Utah's
electric it v.
areas for improving basic chemical reactions. Emissions from industry operations, such as fossil fuel
production and distribution, represent another possible area of reduction, though significant
investment in infrastructure must be made. Finally, increased attention has been focused on public
waste management operations in recent years. Notably, projects are currently proposed for both
municipal wastewater and landfill methane capture.
Land Use Planning
As compared with the other sectors, land use planning does not readily lend itself to the analysis of
individual GHG reduction measures. Specifically, the analysis is complicated by the fact that
multiple energy-consuming activities, such as building energy consumption and transportation, are
inextricably linked in agiven land use plan. Therefore, it is virtually impossible to compare multiple
land use plans and identify the specific reduction potential as one might in comparing, for example,
different end-use efficiencies or modes of transportation. As a result, GHG reduction potential in
this sector is discussed qualitatively with only rough estimates identified for planning variables such
as mix of energy-consuming activities, land use designation, density, and siting. It should be noted,
however, that land use planning may ultimately provide very significant savings since basic
alterations in building and transportation infrastructure lead to relatively permanent changes in
overall energy consuming activity.
Page 4-22
Part Four: Utah Energy Baseline
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Part Five
Fossil Fuel Mitigation Strategies
I. Overview
The Utah residential, commercial, industrial, transportation, and electric utility sectors are each
examined for GHG mitigation strategies that satisfy the selection criteria established in Part Three.
For several mitigation strategies in each sector, the C02 reduction quantity and its associated cost
are reported for both feasible and potential strategies. The feasible category describes the likely
reduction expected and is based on assumptions regarding technology and market penetration, as
well as political and institutional acceptance. The cost data shown are in levelized dollars per C02
ton reduced in 2010. The cost data were levelized over a 30-year time horizon in order to make the
different strategies comparable.
Due to the cross-sectoral nature of GHG emissions associated with various land use patterns, this
section also includes a separate discussion on land use planning-related mitigation opportunities.
This discussion represents a broader, system-wide approach to GHG emissions mitigation that may
help to augment reductions made in each sector.
II. Residential Sector
A. Introduction
Although the residential sector contributes least to GHG emissions as compared with other sectors,
this sector is important for several reasons. First, it encompasses the physical structures in which
we live and the end-use of the technologies that make these structures comfortable. Clearly our
standard of living depends on conveniences such as heating and refrigeration. Second, the residential
sector also represents a substantial investment of individual stakeholders within our community. For
most people, purchasing a home is the most significant investment that they will make. Even for
renters, the total amount of money devoted to provide housing relative to other expenses is large.
The average Utahn spends about 30 percent of their income on housing each year. Third, with regard
to GHG emissions, the residential sector lends itselfwell to mitigation measures. For example many
people with older appliances (which usually use more energy than newer appliances) would save
money in the long run if they chose to purchase a more energy-efficient appliance. In addition, many
people buy new appliances with no thought as to energy efficiency, so the turnover of the appliance
stock allows for gradual, ongoing improvement. Fourth, the residential sector is growing. This
growth is largely the result of substantial population growth, most of which is due to the state's
relatively high fertility rate (2.6 annually compared to the national average of 2.0).
The Utah residential sector is forecast to release 11.6 million tons of C02 by the year 2010, up from
7.8 million tons of C02 in 1990. This represents a total increase of 49.2 percent, or about 2.5 percent
a year. The residential sector accounted for 18.4 percent of Utah's energy-related C02 emissions in
1990 and decreased to 17.9 percent in 1998. By 2010, it should account for 16.7 percent of Utah's
GHG emissions.
Part Five: Fossil Fuel Mitigation Strategies
Page 5-1
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The typical household in Utah is responsible for about 14 tons of C02 emissions annually.
Considering both electricity sales and their associated losses, most of the emissions in the residential
sector, about 62 percent, result from electricity use. Computers, hair dryers, electric stoves, and
other major and minor appliances are powered from an external source. In Utah, this source usually
consists of power plants, with about 95 percent of power generation from coal-fired sources. Each
kWh delivered to the end user at the electric outlet results in about 2.37 pounds of C02 generated
by a power plant.
Strategies to reduce emissions in this sector can be separated into two main areas. The first category
is major electricity end uses, which includes space heating, water heating, refrigerators, and air
conditioning, while the second category includes lighting and appliances. An interesting aspect of
appliances is that this category can also be divided into major and minor uses. Major appliances are
such things as washing machines and clothes dryers. Minor appliances include everyday household
items such as electric razors, blenders, and can openers. While reductions can be obtained within
all appliances, this report focuses on major appliances. One of the criteria in selecting strategies was
that of identifying meaningful strategies of GHG emissions reductions. Though strategies for minor
appliances taken as a whole could lead to a meaningful reduction, as individual appliances they do
not lead to major reductions.
The second type of strategy is to change living conditions and behavior. This type of strategy is not
as neatly defined as energy efficiency measures but it is useful. This type of strategy might involve
changing "structural" elements of a residence. For example, the type and quality of insulation and
windows play an important role in determining the amount of energy used to create heat and air
conditioning. This category of strategies also tries to alter household behavior. An illustration of this
might be a strategy that tries to promote conservation through a public awareness campaign.
Alternatively, conservation could also be encouraged through increasing the cost of electricity
through taxes or other measures.
B. Selected Strategies
Major Appliance Efficiency Gains
Maj or appliances include refrigerators and freezers, cooking appliances, clothes washers and dryers,
and dishwashers. These appliances differ from minor appliances in the amount of electricity they
require to operate. Reducing the amount of electricity that is needed to operate major appliances
maybe an attractive strategy for several reasons. First, increasing the efficiency of maj or appliances
leads to a reduction in GHG emissions. Second, assuming that the cost of increasing efficiency of
these appliances is modest, these improvements will pay for themselves in the form of decreased
electricity bills. Third, improving appliance efficiency allows for a relatively painless transition.
As the stock of appliances turns over, more efficient appliances replace less efficient appliances.
Electric Water Heater to Natural Gas Conversion
Approximately 33 percent of water heaters in Utah are electric, and electric water heaters account
for 13 percent of residential electricity use. Natural gas provides a cheaper and more efficient energy
source for water heating and results in less C02 emissions. Conversion to natural gas has the
potential to reduce C02 emissions 64,000 tons at $20 per ton. A feasible strategy reduces C02
emissions by 10,000 tons at less than $30 per ton.
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Part Five: Fossil Fuel Mitigation Strategies
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Refrigerators
Refrigerators and freezers account for 15 percent of electricity use in the Utah residential sector.
Much can and has been done to increase energy efficiency of these products. Models made in the
1970's use nearly 2.5 times more energy than those sold on the market today. Some refrigerators and
freezers may use 20 percent less energy than the model standards set in 1993, with some models
reaching reductions of up to 40 percent.
Many of the energy-efficiency improvements are simple. For example, models with side-by-side
freezers and refrigerators use more energy than those with a freezer situated above the refrigerator.
The minimum energy efficiency standard for refrigerators and freezers made after 2001 is between
23 percent to 30 percent more efficient than the current level (set in 1993). The average refrigerator
in Utah uses approximately 1,155 kWh per year; the average freezer uses 1,200 kWh per year.
Conservatively assuming that the stock of refrigerators and freezers in Utah meets the minimum
1993 levels, and that these appliances will average a 25 percent efficiency gain, the average
refrigerator sold after 2001 will use less than 850 kWh per year, and the average freezer sold after
2001 will use less than 900 kWh per year. A feasible strategy reduces C02 emissions by 9,000 tons
at $45 per ton. Premium refrigerators have the potential to reduce C02 emissions 150,000 tons at
$45 per ton.
Clothes Dryers
Clothes dryers account for approximately six percent of energy use in the Utah residential sector.
However, clothes dryers do not present a significant opportunity for reductions in energy use. New
technologies may be introduced that lead to reductions. This report, however, makes the
conservative assumption that significant reductions are not feasible by 2010.
Clothes Washers
Clothes washers use more than nine percent of the electricity within the Utah residential sector. The
amount of energy a clothes washer uses is determined largely by design. For example, a tub that is
front loading rather than top loading saves energy. Another factor to consider is the amount and
temperature of water used per load. Energy-efficient clothes washers use less water, particularly hot
water, than less efficient clothes washers.
The EPA's Energy Star® program has identified washers that are at least 30 percent more energy
efficient than those that meet the minimum standards and confers an Energy Star® rating on those
machines if they meet a higher energy-efficiency standard. These more energy-efficient products
often cost more, but they frequently pay for themselves through a reduction in consumer energy bills.
Energy-efficient clothes washers have additional benefits as well. Energy Star® reports than in
addition to using 30-40 percent less energy, these washers use 50 percent less water, cause less wear
and tear on clothes, and extract water better, which may lead to an addition energy savings when a
clothes dryer is used.
Residential Indoor Lighting
Indoor lighting accounts for approximately 12 percent of electricity use in the Utah residential sector.
Lighting is a subtle energy user because it is the cumulative effect of the use of many lights over time
that consumes a substantial amount of energy. Electricity comprises a substantial portion of the
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actual cost of lighting, which can be broken down into bulbs, electricity, fixtures, and wiring. A
feasible strategy reduces C02 emissions by 29,000 tons at $ 16 per ton. Residential lighting has the
potential to reduce C02 emissions by 230,000 tons at $ 12 per ton. The amount of electricity that a
bulb uses is largely dependent on the bulb type. The most common in the residential sector is the
incandescent bulb. Roughly 80 percent of indoor residential lighting is made up of incandescent
lights, the cost of which is fairly inexpensive at roughly $40. A 75-watt incandescent bulb has an
estimated life of750 hours. The average residential light is used roughly 3 hours every day, so bulb
life is estimated at 9 months.
The actual cost of lighting includes fixtures, wiring, and electricity. Under the assumption that
wiring and fixtures are interchangeable between incandescent lighting and fluorescent lighting, the
major variables remain the bulb cost and electricity. Although the fluorescent bulb costs more than
the incandescent bulb, the cost of replacing incandescent bulbs and the additional electricity needed
to use such bulbs is higher that the cost of the costs associated with the life-cycle cost of a
fluorescent bulb. A fluorescent bulb pays for itself in just over 2 years. Comparing the cost of an
incandescent bulb over the lifetime of the fluorescent bulb illustrates that the fluorescent bulb costs
$34 less than the incandescent bulb.
A bulb used to a lesser extent is the compact fluorescent. (The average home pays 0.44 cents an hour
to use a 75-watt bulb, assuming that akWh costs 5.88 cents.) Approximately 20 percent of indoor
residential lighting consists of fluorescent bulbs. The cost of a 22-watt compact fluorescent bulb is
assumed to be $10, with an estimated life span of over 9 years, assuming use comparable to an
incandescent bulb. It would cost the average home 0.13 cents an hour to use, at 5.88 cents per kWh.
Differences of GHG emissions resulting from incandescent bulbs and fluorescent bulbs are
substantial. Fluorescent bulbs use 70percentless electricity than incandescent bulbs. This reduction
of energy directly corresponds to a reduction of GHG emissions.
Building Code Improvements
Building codes set the minium standards to which homes must be constructed. The purpose of these
codes is to standardize buildings to ensure that buildings meet a minimum level of safety, public
health, energy efficiency, conformity with the public infrastructure, and other purposes designed to
promote the public good. In 1978 the State of Utah passed an amendment to the Utah Uniform
Building Standards Act that changed the Utah building standards to match those in the Model Code
for Energy Conservation, a nationally recognized standard. Since its enactment, the Utah Uniform
Building Standards Act has been based on models designed and endorsed by national professional
organizations. Currently the Utah residential code is based on the 1995 Model Energy Code.
Although this is not the most current Model Energy Code, it is still relatively up to date.
Energy Star® Homes
Energy Star® Homes is a program that works with home builders to provide homes that are at 30
percent more efficient than homes built to meet the minimum requirement of the Model Energy
Code. The Energy Star®Homes program rates three major areas: heating, cooling, and water
heating. These areas make up about 37 percent of Utah's electricity use in the residential sector.
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As an incentive to encourage builders to incorporate better building practices, the Energy Star®
Homes program certifies that the home exceeds the Model Energy Code by at least 30 percent. This
program is not designed to address the size of the home but a home's relative energy efficiency level
compared to those in similar environments. This label may act as an additional incentive when
purchasing the home and may lead to preferred mortgage finances from lending institutions since
the label serves as a verification of lower than average energy bills. Exceeding the Model Energy
Code by 30 percent will also cut heating and air conditioning costs in proportion to a decline in
energy use. The label distinguishes energy-efficient homes in the market place.
It is estimated that the average Energy Star® Home costs somewhere within the range of $200 to
$500 more than a home that only meets the minium standards of the Model Energy Code. However,
it is important to note that some home builders have found that energy efficiency does not necessarily
cost more. A building firm in Utah, for example, found that by eliminating some waste within the
construction process it was able to meet Energy Star® requirements without increasing building
costs. Even assuming the initial estimate cost of $500, the average home owner would soon save
considerably each month. Within a few years, this energy-efficiency improvement pays for itself.
The EPA estimates that over the life of a 30-year mortgage, a Energy Star® home owner may save
more than $50,000 through reduced monthly utility bills. Savings occurs when the increase in a
monthly mortgage is less than the decrease in the monthly utility bill.
Weatherization
Weatherization broadly includes various home improvement and maintenance projects that improve
energy efficiency. Examples of weatherization include high-efficiency windows and insulation. This
strategy leads to substantial reductions in residential sector GHG emissions through direct reductions
in electric power and natural gas consumption by households.
Green Power Marketing
Green power is electricity generated by using resources with a minimal effect on the environment.
Energy made from wind, solar, and geothermal resources have the most benign effect on the
environment. Other resources such as hydro, biomass, and natural gas have more impact than the
least harmful resources but less impact than other sources including coal, nuclear, and oil. Green,
however, is a matter of degree. For the purpose of this strategy, Green power includes only wind,
solar, and geothermal resources. A feasible strategy reduces C02 emissions 62,000 tons at $21 per
ton. Green power marketing has the potential to reduce C02 emissions by 124,000 tons at $ 18 per
ton.
Green pricing refers to selling Green power within a regulated environment, presumably at a price
above that of the current rate. The rationale behind such an option in a regulated environment is that
it gives consumers who prefer to use Green power the option to do so. The benefit of such an option
spills beyond that gained by the electricity users who choose to participate in such a program. The
introduction of new renewable resources helps diversify the system, reduces environmental
degradation, and increases system capacity.
Beyond satisfying consumer preferences, Green pricing also provides a substantial potential to
reduce GHG emissions. Of all the sectors, experience from other states shows that the residential
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sector is most likely to participate followed by the commercial sector and the industrial sector. By
2010 it is feasible that 5 percent of the consumers in the residential sector, 3 percent in the
commercial sector and 2 percent in the industrial sector would likely participate in such a program,
given an aggressive marketing campaign.
Net Metering
Net metering provides an additional strategy to provide more electric power generation from
renewable sources. It uses a single meter to measure the difference between the total generation and
total consumption of electricity by customers with small generating facilities by allowing the meter
to turn backward. Net metering can increase the economic value of small renewable energy
technologies for customers. It allows the customers to use the utility grid to "bank" their energy:
producing electricity at one time and consuming it at another time. This form of energy exchange
is particularly ideal for renewable energy technologies. Small-scale electricity generated from
renewable energy sources is sold back to the electric utility at retail prices rather than cost. A
feasible strategy reduces C02 emissions by 46,000 tons at $287 per ton. Net metering has the
potential to reduce C02 emissions by 87,000 tons at $287 per ton.
C. Residential Sector Summary
Table 5-1 presents residential mitigation strategies ranked according to cost. Across the feasible and
potential categories, weatherization, and lighting are the most cost-effective measures. Utility-
sponsored programs such as Green pricing are relatively inexpensive, while net metering, which
entails consumer investment, is the highest-cost strategy in the residential sector.
Table 5-1. Summary of Residential Sector Strategies
C02 Quantity
Cost per ton
(in thousand tons)
Feasib le
Potential
Feasible
Potential
Weatherization
55
388
$4
$3
Lighting
29
230
$16
$12
Green marketing
62
124
$21
$18
Convert water heaters
10
64
$30
$20
Premium refrigerators
9
150
$44
$44
Net metering
43
87
$287
$287
Total
209
1,043
$73
$38
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III. Commercial Sector
A. Introduction
Utah's commercial sector includes the infrastructure that provides for much of Utah's public life.
Schools, churches, government buildings, restaurants, office buildings, stores, and hospitals are
several types of structures that fall into this important sector. These are the buildings that define our
cities and towns, providing the necessary services that enhance our quality of life.
In terms of contribution to Utah's GHG emissions, these buildings are quite significant. Typically
large in size, each building consumes large amounts of energy. Yet an economy of scale tends to
favor large structures, since the cost per square foot of conservation decreases as the size of a
structure increases. As a result, most commercial building owners can readily pay for energy
efficiency improvements through the savings realized on their energy bills.
Utah's commercial sector is forecast to release 14.1 million tons of C02 by the year 2010, up from
7.8 million tons of C02 in 1990. This represents a total increase of 80.8 percent, or about 4.0
percent a year. The commercial sector accounted for 18.1 percent of Utah's energy-related GHG
emissions in 1990 and increased to 19.1 percent in 1998. With the rapid growth of the commercial
sector in Utah, it should account for 20.5 percent of C02 in 2010.
B. Selected Strategies
Lighting
Lighting results in about 35 percent of C02 emissions in the commercial sector. This simple fact,
along with an impressive variety of energy-efficient lighting technologies, introduces significant
opportunities for substantial energy savings. Federal agencies such as the DOE and EPA have long
recognized the potential for energy-efficiency improvements in lighting and have sponsored
numerous programs to encourage more efficient lighting.
Several factors must be considered when evaluating lighting needs and energy consumption. These
include: 1) total floor space; 2) percent of the floor space lighted during usual operating hours; 3)
percent of floor space lighted during off hours; 4) percent of floor space lighted during usual
operating hours that was lighted by each of several lamp types; 5) operating hours per week; 6)
principal activity taking place in the building; and 7) the presence of various lighting conservation
features already in place.
High-Efficiency Lighting Retrofit
This strategy replaces all existing magnetic ballasts and T12 F34 fluorescent lamps with electronic
ballasts and T8 F32 lamps. New ballasts should have a high power factor and low harmonics. The
T8 lamps should be tri-phosphor with average design lumens in excess of 2,550 and a color
rendering index of 75 or higher.
Another strategy is to replace incandescent lamps with compact fluorescent lamps (CFLs). There are
now CFLs available to fit almost any incandescent fixture. A screw-in ballast adapter can be used
or the fixture can be retrofit with a built-in ballast. There are now dimmable units as well. Compact
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fluorescent lamps have a projected life span 10-15 times longer than incandescent lamps, which
makes operation and maintenance savings significant. The payback for a retrofit of fixtures operated
for about 12 hours per day is less than 6 months.
High bay or outdoor lighting systems that use incandescent, mercury vapor, or fluorescent lamps can
be replaced with high-efficiency High Intensity Discharge (HID) systems using metal halide, high-
pressure sodium, or low-pressure sodium fixtures. Exit lights can be retrofited with LED units.
These are more expensive but are very cost effective given their extremely long life and low energy
requirements (on the order of 2 watts).
A feasible strategy results in a 142,000 ton reduction at $20 per ton. Lighting has the potential to
reduce C02 emissions 899,000 tons at $15 per ton.
Lighting Controls
Lighting controls are an additional commercial strategy. At a minimum, occupancy sensor controls
should be installed in irregularly used areas such as restrooms and in common rooms such as break
rooms. These are spaces typically left vacant for extended periods with the lights left on. Lighting
controls result in a feasible reduction of 38,00 tons of C02 at $24 per ton. Lighting controls have
the potential to reduce C02 emissions 284,000 tons at $17 per ton.
Occupancy sensors can be infrared or ultrasonic as appropriate for the space. Infrared sensors detect
the presence of a person by body heat and operate well in areas with obstructions such as restrooms.
Ultrasonic sensors which detect movement are well suited for open areas such as corridors and
conference rooms. Both are available in combination sensor/switch plate units or ceiling mounted
units and the delay prior to unoccupied off switching is adjustable. Typical electricity savings from
occupancy sensors in break rooms is 45-65 percent and 30-75 percent in restrooms.
Ideally, all spaces should have occupancy sensor control. Other options include time-of-day controls
that schedule lighting for expected occupancy hours. Override switches allow temporary lighting
for a specified period during scheduled unoccupied hours.
Controls are also available for use with dimmable ballasts that allow dimming of light fixtures in
spaces where daylight is available.
Heating, Ventilation, and Air Conditioning (HVAC)
Larger commercial buildings differ from residential and smaller commercial buildings both in size
and complexity. Larger commercial buildings tend to have more sophisticated heating and cooling
systems and require much more active ventilation systems in order to maintain air quality. Due to
scale and diversity of needs, a large degree of sophistication is introduced to control air temperature
and air quality. A large building might require cooling a computer room, ventilating a machine
room, and heating business offices. This diversity of needs is served in many large commercial
buildings by a computerized system that regulates heating, ventilation, and air conditioning (HVAC).
Due to the complexity of these systems, it is difficult to generalize about potential energy savings.
Before Congress dissolved the Office of Technology Assessment (OTA), the office published a
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Part Five: Fossil Fuel Mitigation Strategies
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report entitled Building Energy Efficiency. In this report several categorical improvements are
mentioned, including the following:
• improving the efficiency of energy-using devices (e.g., using a higher-efficiency chiller);
• improving the design of the overall system (e.g., routing and designing ducts to minimize
losses);
• switching to different systems (e.g., using a heat pump rather than electric resistance
heating);
• improving system controls (e.g., using outside air for cooling when appropriate);
• improving maintenance (e.g., changing filters as needed); and
• reducing demand for services provided by the system (e.g., installing more efficient lights
to reduce the need for space cooling).
HVAC Automatic Control System
A variety of control systems are
capable of monitoring and
controlling HVAC equipment. The
commercial sector HVAC automatic
control strategy is shown in 5-2.
They result in a feasible reduction
of 25,000 tons of C02 $45 per ton.
HVAC automatic control systems
have the potential to reduce C02
emissions 126,000 tons at $35 per
ton.
A given HVAC system's com-
plexity dictates the level of controls
necessary to effectively manage the
system. For simple heating and cooling, all that may be required are time of day controls with night
time temperature set back. More complex central heating and cooling plants should utilize dynamic
optimal control sequences. This allows maximized performance through fan scheduling, temperature
setback, optimum start/stop logic, discriminator-based discharge air temperature, integrated chilled
water and discharge air temperature control, condensing water temperature adjustment, boiler control
based on outside air temperature, C02-based ventilation control, occupancy sensor controlled air
supply, static pressure reset or terminal regulated volume control on variable volume fans, variable
speed pump control, economizer control, and damper control.
Building Commissioning/Recommissioning
Commissioning is the process of inspecting and testing a building to ensure that all systems are
operating as intended. This process should be completed on new construction and repeated
(recommissioning) periodically over a building's life. The commercial building commissioning/
recommissioning strategy is shown in Table 5-2. It results in a feasible reduction of 98,000 tons of
C02 at $3 per ton. Building commissioning/recommissioning has the potential to reduce C02
Table 5-2. Summary of Commercial Sector Strategies
Quantity
(in thousand tons)
Cost per ton
Feasib le
Potential
Feasib le
Potential
Building Commissioning
98
731
$3
$1
Variable-Speed Drive
Motors
25
172
$14
$11
Lighting Controls
38
284
$24
$17
Lighting
142
899
$20
$15
Plug Load
42
72
$2
$2
HVAC
25
126
$45
$35
Net Metering
57
115
$191
$191
Green Marketing
49
98
$173
$137
Total
458
2,498
$61
$27
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Page 5-9
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emissions 731,000 tons at $1 per ton.
The commissioning process includes verification of proper performance regarding equipment and
installation, controls, operations, and default settings. Tests should verify temperatures, air pres-
sures, damper and valve operations, and control sequences. Switches are checked to confirm they
are in the intended position; mechanical linkages are checked for proper connection and movement;
and heating, cooling, and air flow capacities are confirmed. Each system component is checked to
verify design performance. Occupancy sensors are monitored as well as light and humidity levels.
Fire, safety, and security systems are tested to ensure proper air pressure differentials in the case of
fire, proper emergency lighting and alarms, proper startup of emergency power systems, and proper
lockdown of facilities.
Variable Speed Drives
Variable speed drives should be installed on pump and fan motors allowing variable air volume and
variable flow while eliminating bypass waste. Only the amount of air, water, and glycol necessary
to meet the demand is circulated. This allows motors to operate at lower loads, thereby reducing
electrical energy consumption. This strategy results in a feasible reduction of 25,000 tons of C02
at $4 per ton. Variable speed drive motors have the potential to reduce C02 emissions 172,000 tons
at $ 11 per ton.
Commercial Refrigeration
Commercial refrigeration consists of four major groups: display refrigerators, storage refrigerators,
processing refrigerators, and mechanical refrigeration machines. Within each group of refrigerators,
many different refrigerator models exist. Depending on the use of the refrigerator and the specific
type of model used, different strategies exist for improving efficiency.
Refrigeration accounts for seven percent of electricity used within the commercial sector. Some of
the factors that determine a refrigerator's efficiency include desired refrigerated temperature, the
amount of time the refrigerator is open, the amount of heat to be moved, the degree to which
temperature outside the refrigerator influence the performance of the refrigerator, the quality and type
of material that makes up the refrigerator, the energy efficiency of its parts, and the size and design
of the refrigerator.
Refrigerator improvements can offer impressive energy savings. Due to the size of savings involved,
many of these measures pay for themselves fairly quickly. It is estimated that the energy efficiency
of most refrigerators could improve by 25 percent.
Public Sector Buildings
Public sector buildings, due to the economy of scale in implementing energy efficiency, can offer
tremendous energy savings. In Utah, during the 1999 legislative session, the Quality Growth Act
outlined a plan to utilize savings from such projects. A portion of the savings is returned to the
agency directly benefitting from the savings, and a portion is funneled into the LeRay McAllister
Critical Land Conservation Fund, which is used to purchase open space for preservation.
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The OTA has identified barriers for implementation of cost-effective technologies that are
commercially available. These include the following:
• There is often a separation between those who purchase energy-using equipment and those
who pay to operate the equipment, which undermines existing incentives for efficiency. For
example, one-third ofhousing, and one-quarter of commercial building floor space, is leased
or rented rather than owned.
• Decisions on purchasing energy-using equipment require comparisons across many
attributes, such as cost, performance, appearance, features, and convenience. These other
attributes often overshadow energy efficiency considerations.
• Individuals tend to minimize risk in purchasing expensive equipment. The habit of
purchasing "tried and true" technologies frequently works against the adoption of newer and
more efficient technologies. In short, very few decision makers pursue the goal of
minimizing life-cycle costs (the sum of capital and operating costs over the life of the
equipment), which energy-efficient technologies achieve.
• When trading off cost and energy savings, consumers will not invest in efficiency unless it
offers very short payback periods-less than 2 years for home appliances, for example.
However, personal financial investments generally offer much lower returns.
• Energy cost is relatively low (about 1 percent of salary cost in a typical office, for example),
so those concerned with cost reduction often focus elsewhere.
• Energy efficiency is often misperceived as requiring discomfort or sacrifice, limiting its
appeal.
Due to its size and stability, the government is often better prepared than private and commercial
interests to undertake long-term energy efficiency improvements. As a result, this increased
penetration rate translates into increased GHG reductions from the portion of the commercial sector
or that the public sector represents.
Green Marketing
Beyond satisfying consumer preferences, Green pricing also provides a substantial potential to
reduce GHG emissions. Of all the sectors, experience from other states shows that the residential
sector is most likely to participate followed by the commercial sector and the industrial sector. By
2010 it is feasible that 5 percent of the consumers in the residential sector and 2 or 3 percent in the
commercial and industrial sectors would likely participate in such a program, given an aggressive
marketing campaign. This strategy could result in a feasible reduction of 49,000 tons of C02 at
$173 per ton. Green marketing has the potential to reduce C02 emissions 98,000 tons at $137 per
ton.
Net Metering
The commercial sector net metering strategy is shown in Table 5-2. It offers a feasible strategy that
could result in a reduction of57,000 tons of C02 at $191 per ton. Net metering has the potential to
reduce C02 emissions 115,000 tons at $191 per ton.
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Page 5-11
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C. Commercial Sector Summary
For the commercial sector, the least-cost strategies include investments in building commissioning,
new appliances such as lighting, and process controls such as motors. In parallel with the residential
sector, the highest cost commercial reduction measures include utility-sponsored projects such as
DSM, net metering, and Green pricing.
I Ik' l hill Di'iKirlmi'iil of Natural Kcsources liuildin^
From its orientation to the selection of lighting
and mechanical ?._wem?.. ihe new I'lah
I )epartmeni of\alural Roourcoi I )\R I building
is a $ 1 1.9-million, 105,000-square loot facility
con?.irucled lining a \\iinh--hnihlinapproach lo
ensure the entire building works as a single
system to minimize energy use. The result is a
building de?.igned u> reduce energy con?.umpiion
by 42 percent and ?.a\ e S5<).()()() per year in energy
costs.
A properly oriented IniiUling wilh a large a?.pect
ratio minimizes solar-heat gain while taking
maximumadx antage of abundant nalural day light.
I he new l)NR IniiUling"?. north and mhiiIi exterior
w all?. arc long, allow ing more of the interior to lie
illuminated with the sun's natural light. The
IniiUling'?. eaM and w cm exterior w all?. arc narrow
lo minimi/e unwanted ?.olar gain during I "tali"?,
hot summer months. This feature reduces costs.
A combination of day lighting design technique?,
illuminates interior spaces and corridors with free
sunlight. Light shelves on the south exterior wall
reflect sunlight deep into the building's interior,
more than doubling the area recei\ing natural
light. Light shelves also serve to shade south
lacing window?, from the ?.un"?. direct glare,
reducing the building'?, cooling load and
increa?.ing employee comfort. l'lere?.lory
w indow ?. on ?.ide w all?, allow ?.unlight lo be ?.hared
with interior office?., conference room?., and
hallw ay ?.. I ligh-pcrl'ormancc. low-e gla?.?, allow ?.
70 percent of visible light into the building while
blocking out other light waves that create
unwanted heat. Lncrgy-cfficicnt lighting design
of the l)NR building call?, for two type?. of light
fixtures. T-8 fluorescent ceiling lamps and
electronic balla?.!?. provide a better quality light
and u?.e about hall' the energy of ?.tandard
fluorescent fixtures. Indirect lighting fixtures
bounce light off ceiling?, and wall?, lo provide
more uniform, natural light throughout the
building. Used in conjunction with task lights,
indirect lighting saves electricity by requiring less
than half the light of standard rcccsscd-cciling
fixture?, lo illuminate a comparable ?.pace. I.LI)
exit signs not only use less energy but require less
maintenance and. most importantly. arc more
\i?.ible in a ?.moke-lilled room.
Lighting controls installed in the new building
?.a\e electricity h\ providing light onl\ when
needed. ()ccupanc\ ?.en?.or?. automatical!), turn?,
off lights when an office is not in use. Dimming
ballasts save electricity by controllingthc level of
indirect light fixtures according to amount of
natural light available to the building interior.
Dimming ballasts automatically turn up light
lex el?, on cloud\ da\?. and down on ?.unn\ da\?..
I'lah l)NR take?, advantage ol I tali"?. hoi. dr\
climate h\ u?.ing incxpcn?.i\c. cncrg\ ?.a\ing
direct indirect e\aporati\e cooling technology in
the building. I xpcn?.i\c refrigerated air from
mechanical chillers is needed only on the hottest
day?, of the year. I'o operate the cooling and air
exchange ?.wem?.. the l)NR u?.e?. 1 I motor?, that
require 2-3% less electricity; and 2) variable
?.peed driver?, that make fan motor?, operate at the
minimum ?.peed required to perform the job.
Conventional ventilation systems use less
efficient motor?, that operate at maximum power.
\Vi?.e-water land?.caping and u?.e ol' recycled
material?. aUo empha?.i/e the importance placed
on re?.ource con?.er\ at ion. |OI ¦ K I* "I nergy-
LITicicnt Design."]
Page 5-12
Part Five: Fossil Fuel Mitigation Strategies
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IV. Industrial Sector
A. Introduction
The Utah industrial sector spans a wide range of manufacturing and non-manufacturing activities.
While capital-intensive, resource-based industries have figured prominently in the state's economic
history, today's Utah economy is increasingly characterized by high technology firms that require
less energy per unit output.
T able 5-3 details the energy consumption patterns of Utah's most significant manufacturing andnon-
manufacturing industries by Standard Industrial Classification (SIC) code. Industries generally
consume primary energy in the form of fossil fuels for process or heating applications. Secondary
energy, in the form of electricity, is used for a wide variety of processes such as conveyance, heating,
and cooling. Other important energy uses include space conditioning (heating and cooling),
ventilation, and water heating. Both energy forms are converted into trillion Btus (TBtus) for
convenience of expression.
By SIC category, Petroleum and Coal Products, Chemical and Allied Products, Paper and Allied
Products, and the Primary Metal Industries are the largest consumers of energy in TBtus in the
Industrial sector.
Utah's industrial sector is forecast to release 23.3 million tons of C02 by the year 2010, up from 15.3
million in 1990. This represents a total increase of roughly 52.3 percent, or about 2.6 percent per
year. The industrial sector accounted for approximately 3 8 percent of all C02 emissions in 1990 and
is projected to account for 32 percent of the expected 69.9 million tons in 2010.
Table 5-3. Utah Energy Consumption by SIC Code
Electricity
Electricity
Non-Electric
Total
SIC Industry
Consumption Consumption Consumption
Energy
(million kWh)
(TBtu)
(TBtu)
(TBtu)
20
Food and Kindred Products
394.43
1.35
7.01
8.35
22
Textile Mill Products
221.78
0.76
1.41
2.17
24
Lumber and Wood Products
134.89
0.46
2.98
3.44
25
Furniture and Fixtures
44.81
0.15
0.33
0.48
26
Paper and Allied Products
445.26
1.52
17.14
18.66
27
Printing and Publishing
118.38
0.40
0.38
0.78
28
Chemical and Allied Products
1,036.88
3.54
33.76
37.30
29
Petroleum and Coal Products
240.99
0.82
43.55
44.37
30
Rubber and Misc. Plastics
297.49
1.02
0.99
2.01
Products
32
Stone, Clay, and Glass Products
244.92
0.84
5.77
6.61
33
Primary Metal Industries
982.37
3.35
13.88
17.23
34
Fabricated Metal Products
229.97
0.79
1.78
2.57
35
Industrial Machinery and
217.85
0.74
0.98
1.72
Equipment
36
Electronic and other Electronic
225.41
0.77
0.93
1.70
Equipment
37
Transportation Equipment
263.66
0.90
1.64
2.54
38
Instruments and Related Products
91.73
0.31
0.44
0.75
150.68
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B. Selected Strategies
The Utah industrial sector offers several promising opportunities for energy-efficiency
improvements. Because of the wide variation in production processes and in energy use between
firms in a given industrial category (e.g. steel or refineries) and across different industries, it is
relatively difficult to generalize about energy efficiency opportunities.
Across all industries and fuels, industrial process heating accounts for the greatest fraction of C02
emissions (41 percent), followed closely by general processes including conveyance, air
compression, and motor-related applications (34 percent). Space heating represents 10 percent.
Water heating and process cooling each represent 3 percent of the total. Collectively, these five
processes account for 81 percent of all C02 emissions in the industrial sector. Each process will be
analyzed in turn to identify energy-efficiency opportunities.
Motors
The primary strategy with respect to motors is to optimize motor system efficiency, particularly in
pump systems, fan systems, and compressed air systems. System efficiency can be improved by
reducing the overall load on the motor through improved process or system design, improving the
match between component size and load requirements, use of speed control instead of throttling or
bypass mechanisms, and better maintenance.
Once system efficiency has been optimized, motor retrofits should be made, including the
downsizing of motors. It may be possible to downsize motors. All motor replacements should be
of premium efficiency. The industrial sector HVAC motor strategy could result in a feasible
reduction of 82,000 tons of C02 at a cost of $26 per ton.
Table 5-4. Motor System Energy Use by Major Industry Group
Net Electric
Motor System
Motor System
Industry Categories
Demand
Energy
Energy as %
(million kWh)
(million kWh)
of Total Electricity
Manufacturing
917834
541203
59%
Process Industries (SICs 20, 21, 22, 24, 26-32)
590956
419587
71%
Metal Production (SIC 33)
152740
46093
30%
Non-Metals Fabrication (SICs 23, 25, 36,38-39)
106107
50031
47%
Metals Fabrication (SICs 34, 35, 37)
68031
25492
37%
Non-Manufacturing
167563
137,902
82%
Agricultural Production (SICs 01, 02)
32970
13452
41%
Mining (SICs 10, 12, 14)
44027
39932
90%
Oil and Gas Extraction (SIC 13)
33038
29866
90%
Water Supply, Sewage, Irrigation (SICs 494,
57528
54652
95%
4952, 4971)
Total All Industrial
1,085,397
679,105
62%
Industrial Process
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In 1994, electric motor-driven systems used in industrial processes consumed 679 billion kWh or
23 percent of all electricity sold in the United States. These machines comprise by far the largest
single category of electricity end use in the national economy. According to the EPA's Motor
Challenge Program, industrial motor energy use could be reduced by 11 to 18 percent if all cost-
effective applications of mature and proven energy efficiency technologies and practices were
adopted. Collectively, these technologies could result in energy savings of 75 to 122 billion kWh
with an expenditure of between $11 to $17 billion. Potential savings in the non-manufacturing
sectors could reach as high as 14 billion kWh at the same cost per kW installed.
There are two basic categories of motor system energy efficiency measures: motor efficiency
upgrades and system efficiency measures. The former improve the energy efficiency of the motor
driving a particular machine or group of machines. The latter improve the efficiency of a machine
or group of machines as a whole. System efficiency can be improved by reducing the overall load
on the motor through improved process or system design, improving the match between component
size and load requirements, use of speed control instead of throttling or bypass mechanisms, and
better maintenance, to name just a few of the engineering strategies available.
According to Motor Challenge, motor efficiency improvements alone can lower energy by 2.9
percent. Improved methods of rewinding can account for another 1 percent consumption. Energy
Table 5-5. Industrial Electricity Energy and Emissions Savings
Efficiency Strategy
Cost/kWh
Energy
Cost/Ton of C02
(cents)
Savings(MW) mitigated (dollars)
Equip air compressors with unloading kites
1.4
$39.00
Install unloading valve and accumulator for
2.1
27
$5.99
hydraulic pumps
Install efficient exhaust hoods
2.2
6.7
$62.77
Install electronic variable speed drive to better
3
308
$8.56
control motors
Downsize pumps to better match loads (10 to 5 hp)
4
117
$11.42
Efficient fan motors
4.9
6.5
$140.65
Irrigation pumps
5.1
0.6
$144.90
Downsize motors to better match loads
6
24
$17.13
Install variable speed drive to replace throttling
10
34
$28.55
device to correct for pump over capacity
Install an electronic variable speed drive to better
14
111
$39.97
control motors subject to varying load conditions
(51 to 125 hp)
Install an electronic variable speed drive to better
15
44
$42.82
control motors subject to varying load conditions
(21 to 50 hp)
Replace inlet vanes on air drying fans with a
18
6
$51.38
variable speed motor
Install an electronic variable speed drive to better
18
31
51.38
control motors subject subject to varying loads (5
to 20 hp)
Install oversize piping to lower
33
64
94.2
Source: Northwest Power Planning Council, Conservation Resource Advisory Committee, and PacifiCorp's RAMPP
5.
Part Five: Fossil Fuel Mitigation Strategies Page 5-15
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savings from system-wide efficiency improvements can gain another 9 percent. Overall, these
improvements could gain as much as 13 percent energy savings.
Table 5-4 presents motor system energy use by major industry group for the nation as a whole. The
far right column shows estimated savings which are broadly applicable to Utah.
As indicated in the table, the manufacturing sector accounts for 85 percent of the nation's total
industrial electricity demand. In terms of motor system energy, manufacturing accounts for 80
percent of the total. In this latter category, process industries represent 62 percent of total demand.
The non-manufacturing sector's demand for motor system energy is 20 percent of the total with water
supply, sewage and irrigation accounting for the largest percentage use.
In Utah, electricity is the primary form of energy used in industrial processes. Together with
transmission and distribution (T&D) losses, electricity accounts for 83% of all energy consumed in
the industrial sector. The primary strategy with respect to motors is to optimize motor system
efficiency, particularly in pump systems, fan systems, and compressed air systems. System efficiency
can be improved by reducing the overall load on the motor through improved process or system
design, improving the match between component size and load requirements, use of speed control
instead of throttling or bypass mechanisms, and better maintenance.
Table 5-5 provides a wide array of electricity efficiency strategies for industrial processes listed by
measure cost. Industrial processes collectively account for 6,147 tons of C02, ranked second behind
process heating. Note that costs are levelized over 15 years and do not account for accrued energy
savings. Capacity savings (MW) are cumulative over the 15 year horizon.
Space Conditioning
Space conditioning refers to HVAC applications for the heating and cooling of work spaces. The
following measures include both building shell improvements and HVAC equipment. In this
category, window and solar film are by far the least-cost strategies (see Table 5-6).
Process Cooling
Table 5-6. Industrial Electricity Energy and Emissions Savings
Efficiency Strategy
Cost/kWh
(cents)
Energy Savings
(MW)
Cost/Ton of C02 mitigated
(dollars)
Low E Windows
0.9
19
28
Solar film
3.8
8.6
108.7
Economizers
6.2
5.9
177
Refrigeration Pumps
3.02
3.6
86.1
Source: Northwest Power Planning Council, Conservation Resource Advisory Committee,
and PacifiCorp's RAMPP 5.
Process cooling refers to low temperature modification of production processes. Refrigeration is the
primary application. Pumping costs are offered as the sole measure for which cost and savings have
been estimated.
Process Heating and Water Heating
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Process and water heating accounted for 44 percent of 1998 industrial emissions of C02. In terms
of the fuel used, coal accounted for 50 percent of all emissions, followed by natural gas at roughly
25 percent. Distillate and other fuels largely comprised the remainder with minimal contributions
from electricity. For water heating applications, natural gas and distillate fuel accounted for more
than three-fourths of all C02 produced. Electricity and associated losses made up 14 percent of the
total.
The opportunities for emissions mitigation in these two categories are relatively limited since both
applications generally require the direct use of high-btu fossil fuels for which there are relatively few
substitutes. Precisely because virtually all industries require electricity in addition to thermal energy,
combined heat and power (CHP) projects have become popular strategies for reducing energy
consumption.
CHP refers to the sequential production of thermal and electric energy from a single fuel source. In
the CHP process, heat is recovered that would normally be lost in the production of one form of
energy. For example, in the case of an engine configured to produce electricity, heat could be
recovered from the engine exhaust and used for processes or water heating, depending in part on the
exhaust temperature.
The recycling of waste heat differentiates CHP facilities from central station electric facilities. The
overall fuel utilization efficiency of CHP plants is typically 70-80 percent versus 35-40 percent for
utility power plants. The basic components of any CHP plant include a prime mover, a generator,
a waste heat recovery system, and operating control systems. Typically, CHP systems are configured
around three basic types of generators: 1) steam turbines; 2) combustion gas turbines; and 3) internal
combustion engines. Table 5-9 shows a comparison of energy balances for CHP and central station
facilities.
As apparent from the table, CHP systems succeed in recovering all losses from the condenser and
12 percent from exhaust stacks. Radiated losses, however, are not recovered.
A representative CHP project for Utah
industrial customers would likely
consist of a facility rated at less than 12
MW with a capacity factor of
approximately 80%. These systems are
primarily internal combustion engines
or combustion turbines, generally
using natural gas for fuel. Such
systems reduce energy purchases and
may also increase the reliability of
electric power delivery. In many cases,
industries benefit from sell back tariffs
which compel investor-owned or
public utilities to purchase excess
electricity. Historically, these sell back
tariffs have figured prominently in the
decision to develop CHP projects.
Table 5-7. Energy Balance: CHP Versus Central Station
Energy Balance Stage
Without Heat
Recovery
With Heat
Recovery
Electrical Energy Output
33%
33%
Condenser Losses
30%
0%
Condenser Recovery
0%
30%
Exhaust Stack Recovery
0%
12%
Exhaust Stack Losses
30%
18%
Radiated Losses
7%
7%
Total
100%
100%
Part Five: Fossil Fuel Mitigation Strategies
Page 5-1 7
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For a Utah case study, consider a 4 MW CHP facility. The heat rate (Btu/kWh) for an internal
combustion engine of this capacity is on the order of 4,250, which compares with 11,390 for a
typical coal-fired central station facility. Fixed and variable O&M costs amount to $563,443 and
variable fuel costs are $280,000 rising at a real rate of 2.4% annually. Three levels of capacity factor
are assumed: 70, 80, and 90 percent. Table 5-10 details the tons of C02 reduced in 2010 and the
annualized costs per ton for this example.
Table 5-8. Emissions Reduction and Costs for Combined Heat and Power
Low
Feasible or
Best Estimate
Potential or
High
Tons C02 reduced in
81,449
93,085
104,721
2010
Annualized $/ton C02
14
12
11
Steam System Optimization
This strategy seeks to optimize steam system performance through improved operation and
maintenance procedures. The industrial sector steam system optimization strategy is shown in Table
5-3. It results in a feasible reduction of 83,000 tons of C02 at $13 per ton. Steam system
optimization has the potential to reduce C02 emissions 166,000 tons at $12 per ton.
Several aspects of the industrial steam system operation and performance need to be considered. A
steam balance needs to be developed and actual operating conditions and system requirements for
both winter and summer operating conditions must be considered. Steam excess or deficit must also
be balanced. Optimization includes integrating plant operations to avoid steam venting and cycling
operations with high demand.
Eliminating excess steam is a key aspect of steam system optimization. Opportunities include
shutting down turbines, checking for leaking valves, examining turbines, upgrading turbines, and
varying header.
High-Efficiency Lighting Retrofit
This strategy seeks to replace all existing magnetic ballasts and T12 F34 fluorescent lamps with
electronic ballasts and T8 F32 lamps. New ballasts should have a high power factor and low
harmonics. The T8 lamps should be tri-phosphor with average design lumens in excess of2,550 and
a color rendering index of 75 or higher. The industrial sector lighting retrofit strategy is shown in
summary (Table 5-11). It results in a feasible reduction of59,000 tons of C02 at $6 per ton. A high-
efficiency lighting retrofit strategy has the potential to reduce C02 emissions 94,000 tons at $5 per
ton.
Wherever feasible, incandescent lamps should be replaced with compact fluorescent lamps (CFLs).
There are now CFLs available to fit in almost any incandescent fixture. A screw-in ballast adapter
can be used or the fixture can be retrofit with a built-in ballast. There are now dimmable units as
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Part Five: Fossil Fuel Mitigation Strategies
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well. Compact fluorescent lamps have a projected life span that is 10-15 times longer than
incandescent lamps making operation and maintenance savings significant. The payback on retrofits
of fixtures operated about 12 hours per day is less than 6 months.
High bay or outdoor lighting systems that use incandescent, mercury vapor, or fluorescent lamps may
be replaced with high-efficiency High Intensity Discharge (HID) systems using metal halide, high
pressure sodium, or low pressure sodium fixtures. Exit lights should be retrofit with LED units.
These are more expensive but are very cost effective given their extremely long life and low energy
requirements (on the order of two watts).
C. Industrial Sector Summary
The least-cost reduction strategies in the industrial sector include steam system optimization and
process improvements. Utility-sponsored programs are again ranked among the highest-cost
measures. Additional potential for reduction may occur with large-scale cogeneration.
Table 5-9. Summary of Industrial Sector Strategies
Quantity Cost per ton
Feasible
Potential
Feasib le
Potential
High-Efficiency Lighting Retrofit
59
94
$6
$5
Steam System Optimization
83
166
$13
$12
Motors (HVAC)
82
155
$26
$23
Net Metering
83
166
$48
$48
Green Marketing
33
66
$279
$221
Total
340
646
$49
$47
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Page 5-19
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V. Transportation Sector
A. Introduction
In modern history, few developments have had as dramatic an impact on our way of life as
transportation. Innovations such as rail, auto, and air transport have made the world smaller while
expanding the marketplace. Today we visit destinations that past generations could only imagine
and shop for goods from thousands of miles away.
These innovations, however, have not come without costs, some of which are quite high. As any
commuter who has sat in congested traffic can attest, many of the current modes of transportation
all too frequently fail to save us time - our most irrevocable resource - and considerably degrade our
environment. Exhaust from vehicles makes a significant contribution to Utah's GHG emissions. In
fact, burning just one gallon of gasoline results in approximately 20 pounds of C02.
Strategies to reduce transportation-related emissions can be separated into two categories. The first
involves strategies designed to reduce vehicle miles traveled (VMTs). One strategy, for example,
involves increasing the cost of transportation which tends to reduce the demand for such
transportation. A related strategy turns on decreasing the need for travel. Increased telecommuting
is an example of an action that can reduce or eliminate the original need for transportation. Less
energy-intensive strategies such as car pooling, the designation of high-occupancy vehicles (HOV)
lanes, and larger public works projects such as mass transit can also lead to significant reductions.
The second category of strategy relates to increasing fuel efficiency and reducing vehicle emissions.
These strategies do not affect VMTs per se; rather, the strategies modify the amount of emissions
that current and projected VMTs induce. Of course, reducing emissions per mile may not offset the
increased number of vehicles due to population growth. One fuel efficiency strategy is to encourage
people to drive vehicles that consume less fuel per mile than the vehicles they currently drive. This
may be accomplished through several policy mechanisms including incentives for choosing fuel
efficient vehicles or penalties for choosing inefficient vehicles. Another approach is to encourage
practices that lead to higher efficiency per vehicle such as reducing speed. Other emission reduction
strategies would present only minor inconveniences to drivers. One example is the maintenance of
optimal tire pressure. Still another strategy includes alternative fuels which may provide efficiency
gains without altering driver behavior. Switching fleets from gasoline to natural gas is a common
practice that achieves this type of reduction.
B. Selected Strategies
Optimal Tire Inflation
Vehicles in motion face resistance which lowers their overall efficiency. The most obvious form is
wind resistance which is a function of surface area and design. A less obvious form is frictional
resistance which relates to a vehicle's motion in contact with the road surface. One simple way to
reduce this form of resistance is to inflate tires to an optimal level since an under-inflated tire
increases the surface area of a tire rolling on the road. A program to inflate tires to optimal levels
is a potential mitigation strategy. Additional benefits accrue to the customer by reducing gasoline
consumption, wear-and-tear on tires, and to a lesser extent the vehicle itself. By requiring optimal
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Part Five: Fossil Fuel Mitigation Strategies
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tire levels during annual safety and emissions testing or even as a routine part of regular
maintenance, the state could reduce GHG emissions. As evident, the strategy represents an easy and
inexpensive approach for the state to increase automobile fuel efficiency and reduce GHG emissions.
CAFE Standards and Feebates
In 1976 the federal government established Corporate Average Fuel Efficiency (CAFE) standards
for automobiles and fleet vehicles. When CAFE standards were enacted, the average fuel efficiency
for new vehicles was roughly 17 miles per gallon. The fuel efficiency levels increased dramatically
by 10 miles per gallon in the next 10 years, where they have remained relatively constant. Current
levels stand at about 28 miles per gallon. It is vital to note that sport utility vehicles (SUVs), which
are classified as light duty trucks, are not covered by CAFE standards. SUVs now present roughly
half of all new vehicles purchased, state and federal governments are increasingly interested in
establishing standards for these vehicles.
Many supporters of more efficient vehicles maintain that increased CAFE standards would result in
increased fuel efficiency. The US Office of Technology Assessment (OTA) reports that regulations
could increase fuel efficiency by 20 percent. Automobile manufacturers can meet CAFE standards
in a variety of ways. Regardless of the technology and design modifications, the CAFE standards set
benchmarks that companies must meet or face fines for noncompliance by the U.S. Department of
Transportation.
A feebate program is designed to help consumers internalize some of the costs (externalities)
associated with inefficient vehicles. Feebates differ from CAFE standards by relying more on market
forces rather than regulatory oversight powers.
Feebates establish a mileage target which starts out as the average fuel efficiency (expressed as
average miles per gallon). A fee is charged to purchasers of inefficient vehicles and a rebate is given
to those who purchase efficient vehicles. The fee or rebate is determined by the number of miles per
gallon the vehicle consumes below or above the mileage target. The larger the feebate is for every
mile per gallon above or below the mileage target, the greater the consumer's incentive to choose
a more fuel-efficient vehicle. As manufacturers respond to the demand for more fuel efficient
vehicles, the overall efficiency of the existing vehicle fleet increases. In addition, the change in
demand will also correspond to a change in the feebate mileage target and hopefully prompt a new
set of consumers to respond by buying even more fuel efficient vehicles.
While the federal government may institute such a program, the question remains whether or not
states will be allowed to introduce feebates.
Alternative Fuel Vehicles
One approach to limiting GHG emissions from vehicles is to substitute less polluting fuels. Not
surprisingly, different fuels emit different amounts of GHG per mile traveled. C02 production is a
function of the amount and type of fuel burned whereas other types of emissions are responsive to
changes in the process of burning fuels. Therefore, switching to fuels that emit less C02 is the key
to this strategy.
Part Five: Fossil Fuel Mitigation Strategies
Page 5-21
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A considerable amount of controversy surrounds the issue of emissions released during fuel
production. Unlike tailpipe emissions, these are not as easy to calculate. For example, burning
methanol and ethanol emits less C02 than gasoline per mile traveled. Yet, when production cycle
emissions are included, these two fuels may actually generate higher overall C02 emissions than
gasoline. Since calculating emissions during the production cycle involves many approximations
and differs relative to specific processes, the actual emissions associated with these fuels remain the
subject of debate among scientists.
Even after converting natural gas to a liquid form results in a C02 emissions reduction of about 20
and 12 percent per mile traveled compared with gasoline and diesel, respectively. This fuel is
currently used in several Utah fleets, although currently the percentage of vehicles is small. Due to
federal incentives and standards, it is quite commonplace for organizations with large vehicle fleets
to dedicate a portion of their fleet to natural gas use.
Likewise, switching to liquefied petroleum gas (LPG) would also result in a 18 percent reduction in
C02 emissions compared with gasoline. Currently, however, there is no readily available supply for
large scale fleets. Other states havebegun to introduce large numbers of LPG vehicles into the fleet.
The California GHG report estimates that approximately 40,000 vehicles rely on LPG as a fuel
source.
Conversions to hydrogen as a power source may result in substantial reductions. Hydrogen, a non-
carbon-based fuel, emits practically no C02. Producing this fuel, on the other hand, does lead to
some emissions. The net emissions from production and consumption of a hydrogen power source
are thought to be roughly 40 percent less than gasoline per vehicle mile traveled. This fuel, though
promising, is not commercially available.
Electric vehicles are also considered alternative fuel vehicles. However, it is difficult to approximate
C02 emissions from these vehicles because the electricity may vary in composition; that is, electric
vehicles powered by electricity from "Green" sources (e.g. wind, solar, and hydro) will produce less
GHG emissions than from those vehicles powered by traditional electricity sources (e.g. coal and
natural gas). An estimate from California shows that electric vehicles powered by electricity
produced from a natural gas power plant might reduce emissions by about 20 to 30 percent.
Telecommuting
Telecommuting refers to those programs that allow public or private employees the opportunity to
work in alternative locations to their primary place of work. Generally, telecommuting offers an
employee the opportunity to work at or close to home in order to avoid or reduce burdensome
commutes. Telecommuting typically requires office equipment such as a desk, chair, computer, fax
machine, and/or telephone. Email and the internet are examples of technologies which will likely
improve the prospects of telecommuting.
The benefits of telecommuting are not limited to trip reduction and related savings in GHG
emissions. The practice also saves time, reduces vehicle wear-and-tear, eases road congestion, and
saves on work space, parking, and other infrastructure costs. On a more subjective level, other
benefits include increased contact with family members and potentially reduced child care costs.
Additional benefits not readily measured include increased scheduling flexibility and less
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psychological stress. The percentage of employees in Utah who currently telecommute is relatively
small. However, this is only a fraction of the potential number who could telecommute.
Enhanced I&M
Attention to the operation and maintenance of vehicles can greatly increase performance and fuel
efficiency. One strategy is to expand and enhance inspection and maintenance (I&M) programs to
identify those vehicles with the lowest engine efficiency. Owners of such vehicles could then choose
between making repairs to improve efficiency to acceptable levels or removing the vehicles from
service. Aside from improving fuel efficiency, consistent maintenance includes other benefits that
can lower the life-cycle costs of owning and operating a vehicle.
Retire Older Vehicles
Another strategy is to simply purchase older vehicles in order to get them off the road. Many older
vehicles often are not fuel efficient and produce a considerable amount of pollution. Some estimates
attribute 40 percent of all automobile pollution to only 10 percent of automobiles.
Vehicle Speed Control
Vehicle fuel efficiency is in part a function of speed. As the speed of a vehicle increased beyond 55
miles per hour (mph), fuel efficiency typically declines. Since fuel efficiency and the amount of C02
a vehicle pumps into the atmosphere are directly related, setting and enforcing a 55 mph speed limit
could reduce Utah's C02 emissions. Currently, speed limits throughout much of Utah — particularly
in rural areas — are set well above 55 mph.
Clearly, one disadvantage of lowering and enforcing speed limits is the cost associated with
increased travel time. On the other hand, reduced speeds have historically resulted in fewer injuries
and fatalities from accidents. The ancillary cost and benefit of a given speed limit need to be
considered if Utah chooses to implement this strategy.
Smart Traffic Lights and Highways
City driving is usually characterized by many starts and stops with periods of acceleration and
deceleration. Stop lights, traffic jams, poor drivers, and construction are several factors that impede
the flow of traffic and decrease vehicle fuel efficiency. To remedy these problems, Utah is
implementing the concept of smart traffic lights and highways. Utah adopted an intelligent
transportation system (ITS) which includes coordinated traffic signals, real-time cameras to monitor
road conditions, and electronic road signs to alert drivers ofproblems and suggest alternative routes.
This information is gathered and dispersed from operation centers.
The ITS has additional benefits beyond improving traffic flow and limiting delays. UDOT cites
statistics that ITS reduces accidents and fatalities as well. In addition, vehicles operating with fewer
stops and starts tend to require fewer repairs.
Mass Transit - General
One of the main arguments in favor of mass transit is that it benefits from efficiency gains and
economies of scale; that is, costs provided by large-scale facilities such as rail or bus tend to be much
lower on a per-trip basis as compared with automobile trips. GHG emissions on a per-passenger-
Part Five: Fossil Fuel Mitigation Strategies
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mile basis tend to be lower as well. Additional benefits of mass transit may include increasing
transportation options for the young, elderly, disabled, poor, or other groups disenfranchised by an
automobile-based transportation.
Buses are the primary mode of mass transit in Utah. The Utah Transit Authority (UTA) operates a
regional six county system, although, a considerable number of buses are found in school districts
and, to a lesser extent, private firms. A new twist in Utah's transportation story is the introduction
of the TRAX light rail. The new light rail system opened December 4,1999, under budget and ahead
of schedule, and will cover downtown Salt Lake City and outlying areas along a north-south route.
A University route is planned which will ultimately link the downtown area with the University of
Utah. Finally, while there are no specific plans to date, heavy commuter or regional rail has been
proposed to connect larger cities along the Wasatch Front.
Mass Transit - TRAX
The Utah Transit Authority (UTA) has currently undertaken a project to introduce light rail to Salt
Lake County. This project is known as TRAX, which is short for "transit express." The construction
of a north-south corridor is completed and the north-south rail began service on December 4, 1999.
Powered by overhead electricity lines, TRAX will accelerate from 0 to 55 in 18 seconds and run
from 10000 South and 300 East at the southern terminus to downtown Salt Lake City. The length
of the corridor is 15 miles with 16 stations, many of which will have park-and-ride lots. The rail line
will terminate at the Delta Center in downtown Salt Lake City. The University corridor will extend
2.5 miles from the downtown area to Rice Stadium at the University of Utah.
Each TRAX car will hold approximately 150 people. UTA will operate two cars in tandem, for a
total of 300 passengers, and eventually expand to four cars. UTA estimates that by 2010 approx-
imately 23,000 people will ride TRAX daily on the north-south corridor in addition to new bus
patrons. The University corridor is estimated to have the same ridership and potential ridership as
the north-south corridor.
For purposes of estimating TRAX ridership as a mitigation strategy, an average of 34,000 riders a
day is used as a mitigation strategy. Each TRAX car has an expected life span of 30 years and the
rail itself has an expected life span of 50 years.
Mass Transit - Doubling of UTA Bus Fleet
UTA is faced with a vexing choice of either providing a limited number of areas with frequent
service or many areas with infrequent service. For purposes of equity, the UTA has opted for the
latter choice. If UTA were to double the existing bus fleet, however, it could conceivably provide
service to more areas more frequently. It is estimated that doubling the fleet size would allow riders
to access buses every ten minutes during peak times along the majority of its routes. It is further
estimated that a doubling of the fleet would translate to at least a doubling of ridership. The current
fleet of 500 buses currently accommodates 85,000 passenger trips daily, so doubling the fleet to
1,000 buses would yield an expected ridership of 170,000.
Mass Transit - Regional Commuter Rail
The Wasatch Front Regional Council (WFRC) and the Mountainland Association of Government
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Part Five: Fossil Fuel Mitigation Strategies
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(MAG) and UTA have completed a feasibility study of a heavy rail line to service commuters
between Brigham City and Payson, Utah. Though it is still uncertain whether or not the proj ect will
be implemented, a commuter rail project has the potential to replace vehicle trips from people with
substantial commutes. The project currently under study would have stops in Brigham City, Ogden,
Layton, Salt Lake City, Murray, Midvale, South Jordan-Sandy, Lehi, American Fork, Orem, Provo,
and Payson. The feasibility study estimates that approximately 4,000 riders would use this service
each day on a minimal service level.
Trucking-to-Rail Substitution
The OTA has estimated that the ratio of energy use of trucking compared with rail is 8:1 for intercity
transportation. What is unknown is the destinations of freight carried on interstates that would need
to be on rail for this savings to be realized. It is assumed that most major cities and many smaller
communities have access to both rail and interstates. It is unknown, however, how much any given
shipment would differ in trip distance by rail rather than by interstate. As a safe assumption it is
assumed that even with differing trip lengths, the average shipment could still realize an energy
efficiency gain by switching modes.
Fuel Efficient Airplane Jet Engines
Operating at high speeds and carrying considerable weight, commercial jets consume large quantities
of fuel. New technologies may be adopted to increase fuel efficiency. One strategy is to adopt
"Ultrahigh Bypass High-
Table 5-10. Summary of Transportation Sector Strategies
Efficiency Engines" which
Quantity
could reduce overall fuel
(thousand tons)
Cost per ton
use by roughly 4 percent
Feasible
Potential Feasible
Potential
according to ICF estimates.
ICF notes that such a policy
Tire inflation
48
120
$19
$19
Convert vehicles to natural gas57
95
$88
$88
is cost effective (assuming
Enhanced I&M inspection
48
120
$94
$94
engine use of200,000 miles
Telecommuting
36
60
$108
$108
per year for 15 years under
Rideshare
22
45
$161
$80
current fuel prices), but that
Parking Fees
37
75
$173
$173
the competitive nature of the
Buy out old cars
96
240
$223
$223
airline industry discourages
Convert vehicles to LPG
16
33
$275
$275
the required up-front
Regional (Heavy) Commuter Rail
40
80
NA
NA
investment. Due to the
Light Rail
34
80
NA
NA
interstate nature of the
Light Rail Doubled
68
160
NA
NA
airline industry, federal
Double Buses
45
45
NA
NA
action rather than state
Truck-to-rail substitution
180
240
NA
NA
action would likely be a
Heavy-duty Trucks
98
146
NA
NA
more feasible approach if
Jet Engine Efficiency
29
86
NA
NA
regulation is required to
Feebate for mpg
192
480
NA
NA
induce efficiency improve-
55-mph speed limit enforcement
634
961
NA
NA
ments.
Smart Traffic Lights and Highways
48
96
$7
$7
Total
1,728
3,161
$134
$122
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C. Transportation Sector Summary
Transportation GHG reduction measures are among the most capital-intensive for any sector. Cost
per ton reductions, therefore, are proportionately greater than those in other sectors. Among the least
expensive measures are smart traffic systems, tire inflation, inspections, and telecommuting. Cost
increases dramatically for strategies such as vehicle conversions and purchases of old cars. Clearly,
the most expensive measures are related to those with high capital costs such as light-rail and
commuter rail.
VI. Electric Utility Sector
A. Introduction
The following examines the cost and emissions reduction potential of a broad range of measures to
reduce emissions from utility generation of electricity for residential, commercial, and industrial use.
Measures including fuel switching, C02 scrubbing, nuclear generation, or other modifications to
large-scale, central stations will not be included. Rather, this section will focus on existing and
emerging "clean" electricity generation technologies such as solar, wind, geothermal, and pumped
storage (hydro). Distributed generation technologies will also be addressed.
The various measures are evaluated in terms of dollars per ton of GHG reduced. Emissions savings
are calculated on a per kilowatt-hour (kWh) basis. Emissions from generating facilities are compared
to those from the current portfolio of Utah generating facilities (system average) which are estimated
at 0.945 tons per MWh.
The costs of alternative generating technologies have been compared to electricity generation costs
on a per kilowatt-hour (kWh) basis. For measures compared with system average-electricity costs,
the system average is estimated at 2.5 cents per kWh. This figure is based on the variable (fuel,
operating, and maintenance) costs of producing electricity from all generation facilities.
In many cases, transmission and distribution (T&D) credits have been subtracted where measures
could be expected to help avoid investments that would otherwise be required. Capacity credits have
further been applied when measures could be expected to provide new capacity or to reduce the need
for planned new capacity.
It is also assumed that most alternative supply technologies will benefit from minimal incentives
extended by the state and federal governments and regulated utilities. These incentives are estimated
between 0.05 and 0.50 cents per kWh as applicable. Note that all projects are evaluated in levelized
fashion using a real discount rate of 5 percent over a 30 year time frame.
Cost and performance parameters for the following selected strategies are adapted from PacifiCorp' s
RAMPP-5 (Resource and Market Planning Program), the utility's ongoing integrated resource
planning process.
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B. Selected Strategies
Solar (photovoltaic)
RAMPP-5 specifies that Utah could theoretically host a 50 MW photovoltaic facility. The dollar per
kW for the facility is estimated at $3,000, a figure lower than PacifiCorp's estimate ($4,763) which
does not assume a significant price decline for the foreseeable future. A fixed charge rate of 8.4
percent is applied to account for depreciation, insurance, and tax costs. With a capacity factor of 30
percent, total annual kWh is estimated at 197 million kWh.
Project and capacity charges are 16.07 cents perkWh. Fixed O&M costs are estimated at 25.3 cents
per kWh and variable O&M costs are estimated at 0.349 cents per kWh. With no fuel costs, and
credits for capacity and T&D, the adjusted cost of energy (ACOE) is estimated at 40.92 cents per
kWh, yielding a cost per ton of $406.52. Table 5-19 below provides more information on the levels
of reduction relating to three levels of kWh output.
Table 5-11. Solar PV Cost and C02 Reduction
Low
Feasible or Best
Potential or
Estimate
High
Tons C02
186,259.50
372,519.00
558,778.50
Annualized $/ton CO,
$406.52
$406.52
$406.52
Geothermal
In addition to the 23 MW Blundell geothermal plant currently operated by PacifiCorp, the RAMPP-5
modeling process indicates that Utah could host added geothermal capacity. The proposed project
is rated at 50 MW with a capital cost of $2,376 per kW. The fixed charge rate is somewhat higher
at 10.5 percent as is the capacity factor (80 percent). Total annual generation is estimated at 350
million kWh.
Project and capacity charges are 7.25 cents per kWh. Fixed O&M costs and variable costs are
estimated at 3.2 cents and 0.2 cents respectively. Including government and utility incentives, the
ACOE is 8.69 cents per kWh. The cost per ton of C02 reduced is calculated as $84.69. Three levels
of reduction potential are included based on installed capacity.
Table 5-12. Geothermal Cost and C02 Reduction
Feasible or
Potential or
Low
Best Estimate
High
Tons C02
372,519.00
745,038.00
1,117,557.00
Annualized $/ton CO,
$84.69
$84.69
$84.69
Hydro (pumped storage)
PacifiCorp has modeled pumped storage operations for its hydroelectric facilities. A proposed 200
MW facility carries a capital cost of $816 per kW. The fixed charge is estimated at 15 percent and
the capacity factor at 30 percent. Annual generation is figured at 526 million kWh.
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Table 5-13. Hydro (pumped storage) Cost and C02 Reduction
Feasible or
Potential or
Low
Best Estimate
High
Tons C02
496,692.00
496,692.00
496,692.00
Annualized $/ton CO,
$65.53
$65.53
$65.53
Project and capacity charges are 6.29 cents perkWh. Fixed O&M costs are calculated as 3.2 cents
per kWh with no accounting for variable O&M costs.
The ACOE is calculated as 8.69 cents per kWh, yielding a cost per ton reduction value of $65.53.
As Table 3 indicates, since only one pumped storage project is proposed, there is no variation in
reduction potential.
Wind Power
Among the more economically viable generation technologies is wind power. PacifiCorp proposes
a modest level of wind capacity (50 MW) in its RAMPP-5 model. Capital costs are estimated at
$1,215 and the fixed charge rate is given as 8.4 percent. A 30 percent capacity factor gives rise to
an annual generation level of 131 millionkWh. Project and capacity charges are 6.51 cents perkWh.
Fixed O&M costs are minimal at 6.4 cents per kWh with no assumed variable O&M costs.
The ACOE for with the basic wind project is 12.12 cents per kWh. The cost per ton of emissions
reduced is estimated at $101.66. As many as three projects are considered in the "potential or high"
case. Table 5-22 presents these estimates.
Table 5-14. Wind Power Cost and C02 Reduction
Feasible or
Potential or
Low
Best Estimate
High
Tons C02
124,173.00
248,346.00
372,519.00
Annualized $/ton CO,
$101.66
$101.66
$101.66
Distributed Resources
Distributed resources refer to the combined or individual use of electricity generation, storage,
distribution, load management, and efficiency measures in specific locations to delay or eliminate
transmission and distribution (T&D) system capital investments.
Table 5-15. Range of Distributed Power
Technologies
TECHNOLOGY
SIZE-RANGE
Microturbines
30 - 200
kW
Miniturbines
200 - 1,000
kW
Small Turbines
1,000 - 15,000
kW
Reciprocating Engines
30 - 15,000+
kW
Fuel Cells
30 - 1,000
kW
Fuel Cell Hybrids
200 - 1,000
kW
Source: Power Value. May/June 1999.
Distributed power technologies include renewable
(such as solar photovoltaics, and wind) as well as
reciprocating engines, microturbines, and fuel cells.
Table 5-23 presents a range of common distributed
power technologies.
Current trends in the U. S. energy industry clearly favor
the adoption of distributed generation, particularly from
the standpoint of increased energy efficiency and
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reduced GHG emissions. The characteristics of these technologies and locations (close to the load
served) make them ideal resources to help energy suppliers address regulatory, environmental, and
competitive challenges in delivering essential power services to a range of power customers.
While the above technologies may ultimately prove of great value in diversifying the nation and
Utah's portfolio of generation resources, it is the large-scale, utility-sponsored projects which will
likely prove to be more economically attractive in the near term. This section, therefore, focuses
specifically on distributed generation relating to the avoidance of T&D investments by an
independent distribution company (DISCo) or the distribution end of an integrated distribution,
transmission, and generation utility.
A prime candidate for utility-sponsored distributed generation is a simple cycle combustion turbine.
RAMPP-5 provides cost and performance parameters for a 135 MW system. Such a facility carries
a capital cost on the order of $461 per kW, with a fixed capital charge of 15 percent, and a capacity
factor of 80 percent. Annual generation is estimated at 946 million kWh.
Table 5-16.
Feasible or
Potential or
Low
Best Estimate
High
Tons C02
421,005.60
842,011.20
1,263,016.80
Annualized $/ton C02
$147.35
$147.35
$147.35
Tons C02
617,474.88
1,234,949.76
1,852,424.64
Annualized $/ton C02
$32.52
$32.52
$32.52
Project and capacity charges are 1.33 cents per kWh. Fixed O&M and variable costs are estimated
at 5.3 cents and .01 cents respectively. Fuel costs are estimated at 2.4 cents per kWh, rising at a real
escalation of 2.5 percent annually.
• Simple-Cycle Combustion Turbines
Project and capacity charges are 1.33 cents per kWh. The ACOE for the simple-cycle
combustion turbine is 9.06 cents with an annualized dollar per ton reduction cost of
$147.35. Table 5-16 below shows the varying levels of reduction based on installed
capacity and generation.
• Combination Combustion Turbines
The combination of combustion turbines, configured as topping and bottoming cycles, is
known as a combined cycle facility. Operated as such, these facilities exploit the
thermodynamic advantages of cogeneration systems which recycle waste heat for use in an
additional turbine. As a result, a given amount of fuel is worked twice to improve the unit's
overall efficiency. RAMPP-5 identifies this technology as appropriate and viable for Utah.
Specifically, PacifiCorp is considering a 198 MW facility with a capital cost of $561 per
kW. With a fixed capacity charge and a capacity factor of 80 percent, such system is
Part Five: Fossil Fuel Mitigation Strategies
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capable of producing 1,390 million kWh per year.
Project and capacity charges are 1.62 cents per kWh. Fixed O&M and variable costs are
1.2 cents and 0.05 cents respectively. Fuel costs are estimated at 1.4 cents per kWh and are
expected to rise at a real annual rate of 2.5 percent. The ACOE is estimated at 3.95 cents
per kWh and the cost per ton of C02 removed is $32.52. Table 5-16 above shows the
potential reduction for differing levels of generation.
VI. Land-Use Planning
A. Introduction
America's cities and towns account for over 80 percent of national energy use. Land-use planning
and urban design affect about 70 percent of that amount, or 56 percent of the nation's total energy
use. For example, the density, mix, and spatial arrangement of land uses in a community heavily
influence the amount and mode of travel and, therefore, transportation energy use. These same urban
characteristics also affect the amount of energy needed to heat and cool private buildings and operate
public or community infrastructure.
The Spatial Patterns of Energy Use and Emissions
According to Owens (1986), several dimensions of urban planning influence energy demand and,
ultimately air quality. These dimensions and related effects on energy demand are found in Table 5-
17 below.
Table 5-17. Influence of Urban Planning on Energy Demand
Energy and Air Quality Link
Planning Variables
Shape of urban boundaries
Shapes and sizes of land-use
designations
Mix of activities
Density/clustering of trips
Density and mix
Site lay out/orientation
Siting/landscaping
Travel requirements
Travel requirements (trip length
and frequency)
Travel requirements (trip length)
Transit feasibility
Space conditioning needs and
district energy
Effect on Energy Demand
Energy use variation up to 20%
Variation up to 150%
Variation up to 130%
Energy savings of up to 20%
Savings of up to 15%. Efficiency
of primary energy use improved
up to 30% with district heating
and cooling.
Energy savings of up to 20%.
Energy savings of at least 5%;
more in exposed areas
Solar use feasibility
Microclimate improvements
Source: Owens, Susan E., Energy, Planning and Urban Form, Pion Publishing, London, 1986
Page 5-30
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Table 5-18. Typical Community Energy Uses
Energy Use
(MMBtu/yr)
Energy Cost
($/yr)
(C02 tons/yr)
Single-family home (2.5 persons)
110
$1,280
13
10,000 sq. ft. store
850
$10,240
129
20,000 sq. ft. office
2080
$25,180
317
Auto (avg. 1.1 occupants)
80
$740
6
Bus (avg. 10 occupants)
1300
$10,380
103
Total Per Capita
50
$1,650
17
Sources: EIA, Annual Energy Outlook 1994. EIA, Commercial Buildings Survey 1993. USDOE, Transportation
Energy Data Book 1994.
Table 5-19. Energy Effects of Residential Density (Total operating energy use per household)
Units/Acre
Energy (MMBtu/yr)
Cost ($/yr)
C02 (tons/yr)
3
440
$4,800
50
6
410
$4,600
49
12
380
$4,300
47
24
360
$4,100
47
48
340
$3,900
45
96
310
$3,700
42
Sources: EIA, Annual Energy Outlook 1994. EIA, Commercial Buildings Survey 1993. USDOE Transportation
Energy Data Book 1994.
Creating energy efficient communities requires measuring energy demand and supply for housing,
employment, transportation, and infrastructure. These measurements are similar to other calculations
that tabulate dwellings, residents, workers, traffic, and other variables used in city planning. Table
5-18 provides an overview of common energy uses.
Density is a key variable in the urban energy and emissions relationship as demonstrated by Table
5-19, which shows the relative difference between residential densities. A description of each density
scenario follows below:
• 3 units/acre - Assumes single-family subdivisions on 10,000 sq. ft. lot which are auto
dependent.
• 6 units/acre - Includes detached housing on 5,000 sq. ft. lots with commuter-oriented
transit service available.
• 12 units/acre-Townhouses are situated on 2,500 sq. ft. lots, with attached walls to reduce
Part Five: Fossil Fuel Mitigation Strategies
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energy use, and a high level of transit service to employment centers.
• 24 units/acre - Assumes low-rise apartments with walking and transit trips equal to auto
use. Shared walls contribute to lower energy use per apartment.
• 48 units/acre - This scenario consists of mid-rise apartments wherein transit and
pedestrian trip exceed auto use and energy use per apartment is reduced further.
• 96 units/acre - This residential density consists of high rise, very high transit and
pedestrian activity. Very low building energy use per apartment is assumed.
Table 5-20. Urban Energy Use Per Household
Activity
Energy (MMBtu/yr)
Cost ($/yr)
C02 (tons/yr)
Travel
80
$910
6
Home
100
$1,220
12
Community Fraction
140
$1,650
21
Total
320
$3,780
39
Sources: EIA, Annual Energy Outlook 1994. EIA, Commercial Buildings Survey 1993. USDOE Transportation
Energy Data Book 1994.
Energy demand and emissions are also greatly influenced by residential spatial patterns. Tables 5-20
and 5-21 below show the relative differences in energy consumption and C02 emissions between
urban and suburban households. The categories of energy demand and emissions include travel,
home, and "community fraction." Community fraction includes the household share of all non-
residential energy use and community infrastructure energy use. For purposes of comparison, each
household is assumed to have 2.5 persons.
Table 5-21. Suburban Energy Use Per Household
Activity
Energy (MMBtu/yr)
Cost ($/yr)
C02 (tons/yr)
Travel
140
$1,670
11
Flome
110
$1,340
14
Community Fraction
190
$2,280
29
Total
440
$5,290
54
Sources: EIA, Annual Energy Outlook 1994. EIA, Commercial Buildings Survey 1993. USDOE Transportation
Energy Data Book 1994.
Among the prime land-use planning strategies for mitigating GHG emissions is mixed use. Table
5-22 below shows the energy and emissions associated with various mixes of offices and residences.
Energy use is limited to building and travel only and the community fraction is not included. Jobs
are limited to offices only.
Land-Use Planning in Utah
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The current period of land-use and growth planning in Utah began in earnest with the 1995 Growth
Summit, a conference sponsored by legislative leadership and the Governor intended to promote
legislative solutions to the growth challenges facing the state. Over 60 proposals suggesting ways
to manage the state's growth were submitted. The Summit resulted in a 10-year transportation
improvement plan for the state.
Table 5-22. Energy Effects of Land-use Mix
Land-Use Mix/Acre
Energy (MMBtu/yr)
Cost ($/yr)
C02 (tons/yr)
Retail
61100
$566,400
5020
Office
17000
$168,300
1660
Jobs/Housing (4:1)
8200
$83,800
860
Jobs/Housing (1:4)
4600
$48,500
530
Jobs/Housing (1:1)
5500
$57,700
620
Sources: EIA, Annual Energy Outlook 1994. EIA, Commercial Buildings Survey 1993. USDOE Transportation
Energy Data Book 1994.
The following year the Governor created the Utah Critical Lands Conservation Committee. The
Committee supported numerous open space proj ects and developed educational materials describing
the tools and techniques for open space conservation.
In 1997, the state partnered with Envision Utah, a public/private community partnership to study the
effects of long-term growth along the Greater Wasatch Area of northern Utah, creating a publicly
supported vision for the future, and advocating the necessary strategies to achieve this vision.
Governor Leavitt is the Honorary Co-Chair of Envision Utah. Concurrently, the Quality Growth
Efficiency Tools (QGET) Technical Committee was formed. Sponsored by the Coalition for Utah's
Future, Envision Utah and its partners - with extensive input from the public - aim to create a
publicly supported growth strategy that will preserve Utah's high quality of life, natural environment
and economic vitality during the next 50 years.
The Role of Envision Utah
The Envision Utah partnership includes state and local government officials, business leaders,
developers, conservationists, landowners, academicians, church groups and private citizens. This
unique and diverse coalition is collaborating to produce a common vision for the Greater Wasatch
Area - the region bordered by Brigham City in the north and Nephi in the south, and stretching from
Heber City in the east to Tooele in the west - as it confronts the prospect of growth in the coming
decades.
The Public's Role in Envision Utah
Vital to the success of Envision Utah's efforts is public input. Meetings, surveys and open workshops
have been held throughout the region and will continue to occur as Envision Utah's efforts proceed
throughout 1999. Particularly crucial is citizen input on the four alternative growth choices. The
ideas and opinions contributed during this phase will be key to the creation of a preferred growth
choice, which will be used as a guide for determining how the Greater Wasatch Area will grow in
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the years ahead.
The Envision Utah Process
The first phase of the Envision Utah process is the development of a broadly supported strategy to
guide the future of the Greater Wasatch Area. From its inception, Envision Utah began the challenge
of bringing together major public and private entities for a cooperative effort to deal with Utah's
growth. Specifically, the work of Envision Utah includes:
• An in-depth study and a broad survey of area residents, conducted by the research firm
Wirthlin Worldwide, to determine Utahns' values and to find out what they most want to
preserve or change in the face of Utah's rapid growth. (May 1997)
• A baseline model generated with extensive state-of-the-art computer tools (Quality Growth
Efficiency Tools - QGET) by the Governor's Office of Planning and Budget. This model
projects the effect of Utah's growth during the next 20 to 50 years if current trends continue.
(September 1997)
• A series of public workshops held throughout the Greater Wasatch Area, which collected
opinions and data from citizens on how to shape future development. These workshops -
which included extensive work on regional maps and explored important topics such as land-
use, transportation and open space preservation - provided valuable public input, which has
been vital to the development of four alternative growth scenarios. (Spring and Summer
1998)
• The development of four alternative growth scenarios, which show possible development
patterns that could result if various growth strategies are implemented during the next 20 to
50 years. An extensive analysis of these alternative scenarios was conducted to determine
and demonstrate the relative costs and impacts of each strategy on population, infrastructure
cost, air quality, water, open space and recreation preservation, traffic congestion, affordable
housing, business patterns and other significant topics. (Fall 1998)
• A widespread public awareness, education and mass media campaign to encourage area
residents to express their preferences on how they want their communities and the region to
develop, and to increase understanding of the options and challenges inherent to growth. In
addition to a thorough public survey, a series of workshops will be held to garner public
input regarding specific growth scenarios. (Winter and Spring 1999).
• The development of a preferred growth scenario which will serve as a broadly and publicly
supported growth strategy for the Greater Wasatch Area in the years to come. (Summer and
Fall 1999)
Implementation
Through a multi-year implementation plan, Envision Utah will promote the publicly supported
strategy in order to improve growth management and land-use policies and practices, at all
appropriate levels throughout the region. In addition, all public and private entities will be
encouraged to voluntarily make planning decisions consistent with the vision of the preferred growth
scenario vision.
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In-Depth Scenario Analysis
Scenario A
Scenario A demonstrates how the region could develop if the pattern of dispersed development
occurring in some communities today were to continue unabated. New development would likely
take the form of single-family homes on larger, suburban lots. Most development would focus on
automobile convenience, and transportation investments would support auto use.
Average lot sizes and concise distances between homes would increase. Most housing would be
single-family homes on larger lots ('A acre and larger), providing many with opportunities for large
yards and suburban living. This could, however, create a shortage of rental housing in the region,
which the market would accommodate by encouraging conversion to more single family homes into
rental properties. The larger lot sizes would cause more new land to be developed in Scenario A than
in any of the other scenarios, leaving less land for open space and agriculture. The supply of
undeveloped land would diminish more quickly, possibly causing an increase in land and housing
costs. Infrastructure costs (transportation, water, sewer, and utilities) would also increase because
of additional roads and longer transmission lines. These infrastructure costs would vastly exceed
those of any other scenarios.
Because development would cover a larger area and travel would be more auto-oriented, Scenario
A would require significant freeway system expansion and more miles of new arterial streets. Mass
transit would not serve the dispersed population very effectively. Most of the transportation
investment would be geared toward improving automobile use. The increased investment would
result in faster speeds, but the dispersed development pattern would cause longer trips, with the end
result being about the same amount of time spent on the road.
Characteristics
Housing:
• People live farther apart and have more privacy
• Most new homes are single family homes on large lots
• Fewer housing choices than today; less housing available in all categories except large-lot,
single-family
• Single-family homes would represent 77 percent of the housing mix, up from 68 percent in
1990
• Average size of single family lot increases from 0.32 acre today to 0.37 acre in 2020
Transportation:
• People benefit from convenience of automobile travel
• Fewer transportation choices, due to increased reliance on automobile travel
• Families will require more cars
• More money required for highway development
• Only 1.5 percent of population has easy access to rail transit
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Land:
• Land is consumed faster than other scenarios
• Urbanized area grows by 95 percent from 1998-2020
• Open space and farmland are consumed more rapidly than in any other scenario
• Re-use of existing urban areas is minimal
Cost:
• Affordable housing farther away from jobs and services as compared with other scenarios
• Infrastructure most expensive of all scenarios
• Personal transportation costs highest of all scenarios
Water:
• Water demand highest of all scenarios, primarily because of outdoor water use
Air Quality:
• More vehicle travel creates worst air quality of all scenarios
Scenario B
Scenario B shows how the region would develop if state and local governments followed their 1997
plans. Development would continue in a dispersed pattern, much like it has for the past 20 years, but
would not be as widely dispersed as in Scenario A. New development would primarily take the form
of single-family homes on larger, suburban lots ('A acre and larger). Most development would focus
on convenience for auto users and transportation investments would support auto use.
Lot sizes and distance between homes would remain near their current averages. Most new housing
provided would be single-family homes on large lots, providing many residents with opportunities
for large yards and suburban living. There could be a few more rental opportunities than in Scenario
A, but could still fall short of meeting current market demands. Many single family homes would
likely be converted into rental properties to meet the extra demand. This scenario would consume
a large amount of raw land, although not as much as Scenario A, limiting the land available for open
space and agriculture.
The available supply of land would be consumed quickly, possibly leading to increased land and
housing costs. Infrastructure costs (transportation, water, sewer, and utilities) would also increase
over the next 20 years, and would be the second highest of all scenarios. Transportation expenditures
would be focused on upgrading the existing freeway system and extending surface streets into newly
developed areas. Street and highway expenditures would be lower than in Scenario A, but speeds
would be lower as well. Although this scenario does not add any rail transit beyond the
Downtown-Sandy line currently in operation, it does envision some expansion and reconfiguration
of bus service.
Characteristics
Housing:
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• Average lot size remains at current level
• Most new homes are single family homes on large lots
• Fewer housing choices than C & D; less housing available in all categories except large-lot,
single-family
• Single family homes would represent 75 percent of the overall housing mix, up from 68
percent in 1990
• A few more condos, apartments, small lot homes than A
Transportation:
• People benefit from convenience of automobile travel
• Fewer transportation choices, due to increased reliance on automobile travel. Compared to
the other scenarios, this means:
• Increasing vehicle travel
• Families need to own more cars
• Increasing congestion
• Only 1.7 percent of population has easy access to rail transit
Land:
• Land is consumed almost as quickly as in A
• Urbanized area grows by 75 percent from 1998-2020
• Reuse of existing urban areas is minimal
Cost:
• Few affordable housing options near jobs and services
• Infrastructure second most expensive of all scenarios
• High personal transportation costs
Water:
• Water consumption second highest of all scenario
Air Quality:
• Second best air quality of all scenarios
Scenario C
Scenario C shows how the region might develop if we were to focus more of the new development
in walkable communities that contained nearby opportunities to work, shop, and play. Communities
would accommodate a portion of new growth within existing urbanized areas, leaving more
undeveloped land for open space and agriculture. New developments would be clustered around a
town center, with a mixture of retail services and housing types close to a transit line. These
communities would be designed to encourage walking and biking, and would contain a wide variety
of housing types, allowing people to move to more or less expensive housing without leaving the
community.
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Average lot sizes would be smaller than today. Most of the new housing provided would still be
single-family homes on large lots, but more apartments, townhouses, condominiums, and small-lot
single-family homes would be provided than in A or B. This would likely meet the market demand
for rental housing. Smaller lot sizes would allow Scenario C to consume raw land less quickly,
leaving more land available for open space and agriculture, and providing suburban and rural living
opportunities further into the future. Infrastructure costs (transportation, water, sewer, and utilities)
would be lower in Scenario C than in any other scenario.
Because Scenario C focuses new development into more compact land-use patterns, walking and
biking would become more feasible. This would also make mass transit a highly effective means of
serving the population, providing a greatly increased number of people with convenient alternatives
to the automobile. Scenario C would therefore propose large-scale expansion of the rail system, and
reconfiguration of bus service to complement rail service. Transportation investments would be
focused much more heavily on transit than they are today, with most road investments going into
improvement of existing roads rather than construction of new ones.
Characteristics
Housing:
• Average size of single family lot decreases from 0.32 acre today to 0.29 acre in 2020
• Homes are closer together; most new homes are single family homes on large lots
• Wider variety of housing options available than in Scenarios A or B, including townhouses,
condos, apartments, and small lot homes
• Much of new housing would be located in villages and towns situated along maj or roads and
rail lines
Transportation:
• More transportation options
• Lower per-person transportation costs
• Families can operate with fewer cars
• Some 25 percent of population has easy access to rail transit
• Rail transit provides convenient access to most Salt Lake area communities
Land:
• Land consumption is slower than Scenarios A and B
• Urbanized area grows by 29 percent from 1998-2020
• New development is placed within existing urban areas and clustered around transit routes,
leaving more land for open space and farmland
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Cost:
• Diversity of housing options makes affordable housing available closer to jobs and services
• Lowest infrastructure costs of all scenarios
• Lower personal transportation costs than A or B
Water:
• Second lowest water consumption of all scenarios
Air Quality:
• Best air quality of all scenarios
Scenario D
Scenario D shows how the region might develop if Scenario C were taken one step further, focusing
nearly half of all new growth in existing urban areas. This would leave more undeveloped land for
open space and agriculture than any of the other scenarios. When new land is used, development
would be clustered around a town center, with a mixture of commercial and housing types close to
some portion of a greatly expanded transit system. These communities would be designed to permit
and encourage walking and biking, and would contain the widest variety of housing types of any
scenario.
Average lot sizes would be smaller than in all other scenarios. Most new housing would be
townhouses and single-family homes on small lots, and more apartments, townhouses,
condominiums, and small-lot single-family homes would be available than in the other scenarios.
Scenario D would consume the smallest amount of new land, leaving more land available for open
space and agriculture than the other scenarios. Infrastructure costs in Scenario D would be lower than
A and B, but somewhat higher than C, as clustering of so many new residents into existing urban
areas would necessitate improvements to existing infrastructure.
Because Scenario D focuses new development into more compact land-use patterns, mass transit
would serve a larger share of the population, providing many more people with convenient
alternatives to the automobile. Scenario D would propose large-scale expansion of the rail system,
with additional spurs for access to downtown Ogden and Provo. Transportation investments would
be focused very heavily on transit, with most road investments going into improvements of existing
roads, rather than construction of new ones.
Characteristics
Housing:
• Average size of single family lot decreases from 0.32 acre today to 0.27 acre in 2020
• Homes are closer together than in all other scenarios most new homes are single-family
homes or townhouses, but on smaller lots than in A or B
• Wider variety of options available than in other scenarios
• Most new housing would be located in existing urban areas and in villages and towns
situated along major roads and rail lines
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Transportation:
• Greatly expanded transit system augments road network to provide more transportation
options
• Some 32 percent of population has easy access to rail transit
• Convenient transit access to most Salt Lake area communities, Ogden, and BYU
Land:
• Land consumption is slower than all other scenarios
• Urbanized area grows by 20 percent from 1998-2020
• Large portion of new development is placed within existing urban areas most other
development is clustered around transit routes, leaving more land for open space and
farmland than any other scenario
Cost:
• Diversity of housing options makes affordable housing closer to jobs and services than in
other scenarios
• Second lowest infrastructure costs of all scenarios
• Lowest personal transportation costs of all scenarios
Water:
• Lowest water consumption of all scenarios
Air Quality:
• Better air quality than in A, worse than B or C
Land-Use Planning and Emissions Reduction
Tables 5-17 through 5-22 (beginning on page 5-32) provide the basic spatial relationships required
to determine how different land-use patterns may provide energy and emissions savings. To a degree,
these relationships may be correlated with Scenarios A through D to determine, in a relative sense,
how each scenario compares in terms of energy consumption and C02 emissions.
According to QGET statistics, Utah will host 775,190 households by the year 2010. According to
the description given for Scenario A, some 77 percent of these households are assumed to be single
and detached, similar to the "3 unit/acre" case in Table 5-19. Assuming that the remaining 23 percent
are based on the "6 unit/acre" model, the total tons of C02 is estimated at 38,581,206.
In Scenario B 75 percent of the households are again characterized according to the 3 unit/acre
model. Based on the description provided by Envision Utah, Scenario B incorporates alternative
housing options including the 6 unit/acre and 12 unit/acre (townhouse) cases. Assuming weights of
15 percent and 10 percent respectively, the total tons of emissions is calculated at 38,410,665.
Scenario C assumes that 75 percent of the single and detached housing is based on the 6 unit/acre
model with the remaining 15 percent and 10 percent consisting of 24 unit/acre (low-rise apartments)
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and 48 unit/acre (mid-rise apartments) cases. Total emissions for this scenario decline to 37,441,678
tons of C02.
Finally, Scenario D assumes that 75 percent of single detached housing is comprised of the 6
unit/acre model with 15 percent based on the 48 unit/acre mid-rise apartments townhouse and 96
unit/acre (high-rise apartments) models. Scenario D yields 36,976,564 tons of C02 per year.
Overall, there is relatively little difference between Scenarios A and B. The savings from Scenario
C over A amount to roughly 1.1 million tons per year. Scenario D saves over 1.6 million tons per
year as compared with Scenario A.
As evident from this analysis, increases in residential density do not provide dramatic gains in
emissions reduction since the proportion of high-density housing in all scenarios, except for Scenario
D, is relatively small. T o fully exploit the benefits ofhigh-density housing, planners should consider,
for example, cogeneration and district energy options to reap the maximum energy efficiency gains.
Part Five: Fossil Fuel Mitigation Strategies
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Part Six
Non-Fossil Greenhouse Gas Emissions
I. Industrial Sources
GHG emissions result not exclusively from the combustion of fossil fuels but also from chemical
and industrial processes. In the U.S. economy, most of these emissions stem from the calcination of
limestone (calcium carbonate, CaC03 to form lime (CaO). Though emissions from calcination are
generally attributed to the cement industry, limestone and lime are used in a wide variety of
industrial applications. Additional carbon is contributed by the production and consumption of soda
ash (Na2C03). Carbon emissions from these sources in the United States have increased in recent
years due to high levels of construction and industrial activity, a trend notable in Utah as well.
A. Limestone Use
Process Overview
Limestone refers to the classification of carbonate rocks used as the basic building blocks in the
construction industry. The primary applications of limestone include aggregate, lime, cement, and
building stone. Limestone can also be used as a flux or purifier in metallurgical furnaces, as a sorbent
in flue gas desulfurization (FGD) systems in utility and industrial plants, or as a raw material in glass
manufacturing. Limestone is heated during each of these processes, generating C02 in the process.
Emissions Reduction Potential
While the production of lime accounts for the majority of carbon emissions associated with the
consumption of limestone, carbon emissions also result from its direct consumption. FGD
commands the largest fraction of the direct use market where limestone is used primarily in coal-
fired electric generating plants to remove sulfur oxides from stack gases either during or after the
combustion of fossil fuels.
The wet lime/limestone scrubber is the most common FGD system, comprising about 70 percent of
all installed FGD capacity in the US. In these systems, flue gas passes through the FGD absorber,
where sulfur dioxide is removed by direct contact with an aqueous suspension of finely ground
limestone, before its release into to the atmosphere from a stack or a cooling tower. The byproducts
of this reaction are either a mixture of calcium sulfate/sulfite or gypsum, which can be sold for use
in plaster, cement, and wallboard.
The demand for FGD systems derive from the 1990 Clean Air Act Amendment. Though highly
efficient at sulfur dioxide removal, FGD is associated with increased C02 emissions for two reasons.
First, as a sorbent, limestone reacts with sulfur dioxide to produce calcium sulfate, C02, and oxygen.
Second, since the FGD requires energy for its function, power plant efficiency is derated by 1 to 2
percent thus increasing fuel consumption to meet electricity loads.
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Because limestone is used directly in chemical reactions, there are relatively few opportunities for
improving the efficiencies of converting it into various products. Co-firing of natural gas with coal
in power plant or industrial applications is perhaps the only strategy that could significantly reduce
the direct use of limestone and, hence, the production of C02 in fossil-fired generation facilities.
The Utah Limestone Industry
Nine companies quarried 2.2 million short tons of limestone and dolomite (a related carbonate
material) in 1998. The three largest suppliers of crushed aggregate used in construction are Valley
Asphalt from two quarries in Utah County, Larsen Limestone from one quarry in Utah County and
Harper construction from one quarry in Salt Lake County.
Geneva Steel quarries their own dolomite and limestone, from a Cambrian carbonate section, for use
as flux at their Orem steel mill. Barring a significant change in its steelmaking process, which is
unlikely given the firm's financial condition, this use will likely remain unchanged or even decline.
Inutility applications, Cotter Corporation mines roughly 25,000 tons per year (tpy) of limestone from
the Pennsylvanian Hermosa Group in San Juan County for FGD at the Nucla, Colorado power plant.
In Utah, Rancho Equipment Service (RES) mines limestone from the Ordovician Pogonip Group in
central Juab County for FGD at the Intermountain Power Project's (IPP) generating station near
Delta in Millard County. RES produces approximately 200,000 tpy for the IPP application. Finally,
the Coval Company produces limestone from the Mississippian Desert Limestone from the old
Larsen Limestone Company property in Utah County for FGD at the Bonanza power plant located
near Vernal. Overall, the demand for limestone in utility applications will track the demand for
electric power both within Utah and for the export market.
In other applications, Emery Industrial Resources mines 30,000 tpy of limestone from the Tertiary
Flagstaff Limestone in eastern Utah County for coal-mine rock dusting. Western Clay Company also
produces limestone from the same area for rock dusting and for crushed stone.
Demand for limestone in these applications should continue to track production at Utah's coal mines,
which in turn are related to electricity production. Utah's Division of Air Quality estimates that year
2010 emissions from this sector should reach 1,007,199 tons. Assuming a 10 percent reduction due
to process efficiency improvements, savings could reach 100,720 tons. Cost effectiveness, however,
cannot be estimated due to a lack of capital cost and O&M estimates for the various processes.
B. Lime Production
Process Overview
A versatile chemical used in a wide range of industrial, chemical, and environmental applications,
lime is a calcined or burned form of limestone commonly referred to as quicklime. Because the basic
production of lime is such as relatively straightforward a process, it has not been the subject of
considerable investigation. Instead, much of the process research has focused on the operation of
kilns. Only in the last 25 to 30 years, prompted largely by higher energy prices, has attention focused
on the thermodynamics and kinetics of calcination and hydration reactions.
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Lime production involves three main stages: stone preparation, calcination or burning, and hydration.
C02 is generated during the calcination stage, when limestone is roasted at high temperatures. In
contrast with the Portland cement industry, which utilizes rotary kilns with preheaters almost
exclusively, lime calcining may employ a wide range of procedures for customized purposes.
Emissions Reduction Potential
Vertical kilns for calcining are typically used for larger stones and may use oil, natural gas, or coke.
In some instances pulverized coal may be used. Multiple shaft kilns are designed for smaller stones
and, because of a novel heat regenerative system, these kilns are among the most efficient.
The most efficient systems overall, however, employ external preheaters in medium length kilns.
With these systems, exhaust gases from the kiln are drawn counter-current through the stone
preheating it to 540 to 900 degrees Celsius. During preheating, approximately 30 percent calcination
is achieved before the stone is discharged into the kiln. Heat exchangers and coolers which
recuperate waste heat are also utilized to affect improved fuel efficiency.
Over the past 30 years the steel industry has been the major consuming market for lime. Imports of
steel and automobiles have curtailed these uses and the likely increased use of polymer composites
will also limit growth in the use of lime in steel production. Nevertheless, the basic oxygen furnace
(BOF) still dominates and continues to use approximately 80 percent of all lime produced. A typical
BOF requires 65 kg/t versus 30 kg/t for electric furnaces or mini-mills. In both of these applications,
lime is used as a scavenger or flux to remove impurities such as phosphorous, silica, alumina, and
sulfur.
Lime is used in non-ferrous metallurgy as a method to neutralize sulfur acid wastes, as a scavenger
for impurities, and as a pH neutralizer. Applications include copper, alumina, and magnesia
production. Lime is also used in the paper and pulp industry for bleaching and in the chemical
manufacturing of alkalies, inorganic chemicals, and organic chemicals. Among the newest
applications for lime include soil stabilization and lime-fly ash for use in roadbed construction.
Among the markets with greatest potential include water and waste treatment and FGD applications.
In the case of water and waste treatment, lime is used in combination with soda ash to soften water
in systems where ion exchange processes are not employed. Lime is also used as a secondary agent
to chlorine for killing bacteria. Finally, lime can be used for absorbing iron, magnesium, and organic
tannins from untreated water.
In the case of FGD, advanced scrubber technologies such as the Dravo Corporation's patented
Thiosorbic process rely exclusively on lime as an absorbent for oxides of sulfur. Overall, the water
and waste treatment and FGD markets should remain strong in the face of ever stringent EPA
requirements affecting water quality.
From the standpoint of energy efficiency improvements, it is important to bear in mind that in each
of the above applications, higher thermodynamic efficiencies have been attained through the
conversion from long rotating kilns to short preheater kilns.
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Table 6-1. Lime Production Unit Operations Table 6-1 identifies the individual
steps or "unit operations" associated
with the production of lime.
Indicated also are the energy inputs
expressed as Btu per unit flow.
As apparent from the table, kiln
operations account for the largest
share of energy input. However,
because most processes are
optimized at this stage, the remaining
areas for reduction are in the
crushing and grinding stages, which
Source: "Energy Analysis of 108 Industrial Processes". Harry L. largely Consist of electric motor
operations. Information on the costs
of motor improvements for these process stages, however, was not recovered. Therefore, no cost
effectiveness measure is offered.
It is assumed that the demand for lime will track the rate of building construction growth. Emissions
are estimated to grow at a rate of 1.9 percent yielding a 2010 GHG emissions estimate of444,732
tons. As compared with limestone, more opportunities exist for efficiency improvements because
the process is more complex and involves more stages. It is estimated, therefore, that process
efficiency could be increased by 15 percent, translating into a year 2010 savings of 66,710 tons.
The Utah Lime Industry
Lime demand and production have remained strong in Utah in recent years. Continental Lime, Inc.,
located east of Sevier Lake, produces about 730,000 tpy of high-calcium quicklime in three rotary
kilns with feed provided by the Cambrian Dome F ormation. Of note, the plant is rated as one of the
10 largest lime plants in the United States. Chemical Lime of Arizona operates a plant near
Grantsville in Tooele County and produces roughly 90,000 tpy of dolomitic quicklime and hydrated
lime from the Ordovician Fish Haven Dolomite. In 1995, the firm purchased the old Marblehead
plant in Tooele County from U.S. Pollution Control.
C. Cement Production
Process Overview
Cement production is among the largest sources of non-fossil emissions in the Utah. Specifically,
C02 results from the heating of limestone, which constitutes approximately 80 percent of the feed
to cement kilns. During cement production, high temperatures are employed to transform the
limestone into lime, releasing C02 to the atmosphere.
Portland cement, the most commonly used hydraulic cement, requires at least four chemical
elements: calcium, silicon, aluminum, and iron. Derived from naturally occurring rocks and minerals
(such as limestone, clay, shale, and iron), the materials are ground into a very fine powder and fed
into a rotary kiln and heated to temperatures up to 1,500 degrees Celsius. It is in the direct firing in
Unit Operation
Electricity Fuel Hot Air
Crushing & Grinding
15.0
Screening & Classify
8.0
Kiln
11.0 2800.00 381.5
Cooling
17.0
Screening & Classify
8.0
Crushing & Grinding
16.1
Hydrator
14.7
Milling Separator
1.0
Packaging
1.0
Electricity Generation
0.3
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the cement kilns that results in calcination and the release of C02.
In this last process, one molecule of calcium carbonate is decomposed into one molecule of C02 and
one molecule of calcium oxide. Because the process consumes nearly 100 percent of the calcium
oxide, the amount ofremaining calcium oxide is a good measurement of the amount of C02 released
during production.
The final product, known as "Portland cement clinker," is then mixed with gypsum and other
chemicals for grinding into a fine powder known as Portland cement. All told, approximately 1.6
tons of dry raw materials are required to produce 1 ton of clinker.
Emissions Reduction Potential
It is vital to bear in mind that cement manufacturing is first and foremost a chemical process. As
such it is dictated by chemical reactions requiring exact amounts of resources at specific
temperatures. There exists, therefore, relatively few opportunities for significant improvement in
process efficiencies. However, significant strides in operational efficiencies have been made over
the past several decades and some opportunities remain.
Over the past several years, due to higher energy prices, the overall manufacturing process has
moved from wet process installations to dry process preheater calciner systems. Such systems
employ large single production lines which replaced the older, multiple line systems. Furthermore,
the dry process reduces energy costs associated with handling wet materials. Overall, the new
manufacturing processes save considerably on labor and energy costs.
At the quarrying phase, impact crushers and dropballs have been employed in place of gyratory and
jaw type crushing equipment. In larger capacity quarries, large diameter blasting has been employed
to save on energy costs associated with heavy machinery operations.
At the initial processing phase, significant amounts of energy are consumed in the physical reduction,
mixing, and blending of materials. Recent developments in drying-grinding mills and heat
recuperating preheaters (added to the available dry blending systems) have greatly reduced costs. For
sulfur dioxide removal, fabric filters have been used in place of electrostatic precipitators, thus
saving further on energy costs. All told, raw materials preparation accounts for about 8 percent of
the energy used to produce Portland cement. Energy efficient technologies could reduce the energy
use in the early stages by about 19 percent.
Clinker production, however is the most energy intensive phase of production, accounting for
roughly 80 percent of energy use. At the burning stage, also known as pyroprocessing, fuel is
introduced into the rotary kilns under slight pressure through a burner tip. Powdered coal or coke is
the preferred fuel for economic reasons; however, No. 6 fuel oil or natural gas is frequently used.
Some kilns, in fact, can lower energy costs by burning wastes such as lubricating oils, spent solvents,
and chlorinated hydrocarbons. State-of-the-art technologies, such as the dry process with either
preheat or precalcine and improvements in kiln refractories, kiln combustion and improved cooling
techniques are estimated to reduce energy by approximately 26 percent from current average
practices.
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Grinding the clinker into a fine powder accounts for 11 percent of the energy use in cement
production. In this stage, air separation is further used for classifying materials. To reduce energy
costs associated with grinding, firms have recently employed pregrinding clinker crushers which
provide savings of up to 28 percent. Higher efficiencies have also been reported with new air
separators. Finally, in the storage and distribution of the final product, conveyor belt transport has
reduced energy costs relative to pneumatic pumping.
Table 6-2 provides the unit operations associated with the production of cement. The table also
shows the energy related processes in Btu per unit flow.
Table 6-2. Cement Production Unit Operations
According to the data presented in
Table 6-2, the crushing and finish
milling stages account for the largest
fraction of electricity consumption in
the cement production process. It is
further apparent that the dry kiln
operations represent a considerable
saving over the wet kiln process.
As with lime production, it is fair to
assume that any increases in process
efficiency will likely be outweighed by
the increased demand for cement
driven by the construction industry.
As with lime, the cement production
process entails numerous stages; hence,
there are several areas for efficiency
improvements. On a weighted average
basis, it is estimated that the
introduction of modern technologies at
critical stages could result in a gain of 28 percent energy efficiency. With forecasted emissions
placed at 596,050 in 2010, this level of savings translates into 165,214 tons.
The Utah Cement Industry
Utah contains vast amounts of the raw materials needed for Portland cement production, including
high-calcium limestone, natural cement rock, high-silica quartzite and sandstone, clay and shale, iron
ore from near Cedar City, and gypsum from Jurassic rock units of central Utah.
Utah hosts two producers: Holnam, Inc in Morgan County and Ash Grove Cement Company in Juab
County. A third plant, whichhasbeen inactive since 1988, was subsequentlypurchased by Mountain
Cement Company for use as a cement shipment terminal.
At its Devil's Slide plant, Holnam uses limestone from the Jurassic Twin Creek Limestone, a natural
cement rock, at its 350,000 tpy wet process plant. As noted above, wet process tends to be somewhat
Unit Operation
Electricity
Fuel Hot Air
Crushing
75.0
Screening & Milling
2.0
Wet Prop & Blending
5.0
Screening & Milling
2.0
Slurry Mix & Blend
2.0
Wet Kiln
10.0
1650.2 204.0
Clinker Cooler
5.0
Prop & Blend
2.0
Drier
270.0
Screening & Milling
2.0
Dry Kiln
5.0
1050.0
Clinker Cooler
5.0
Finish Milling
65.0
Generated Electricity
27.6
Source: Energy Analysis of 108 Industrial Processes. Harry L.
Brown. Fairmount Press Edition: 1985.
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less energy efficient; however, natural cement rock requires virtually no secondary raw materials or
blending activities, thus saving energy.
Other materials used at Holnam include silica from the Triassic-Jurassic Nugget Sandstone, gypsum
from the Jurassic Arapien Shale south of Nephi, and by-product iron from Kennecott Copper
Corporation near Salt Lake City. The Morgan County plant uses primarily coal with natural gas
backup. Of note, Holnam recently announced its intention to convert to a 700,000 tpy dry-process
plant.
East of Lynndyl in Juab County, Ash Grove Cement Company's Leamington plant uses limestone
from the Cambrian Dome Formation adjacent to their 825,000 tpy dry-process, coal-fired plant.
Shale from the County Canyon quarry and silica from the Permian Diamond Creek Sandstone at the
Nielson quarry are used at the plant. Both quarries are located within a few miles of the plant. Ash
Grove also obtains iron from Kennecott slag and Nucor mill scale. Gypsum for retarding setting
times is obtained from the Jurassic Arapien Shale at the T.J. Peck quarry.
In the spring of 1996, Ash Grove increased their plant capacity from 650,000 tpy. Holnam has
recently indicated its intention to double its capacity from 350,000 to 700,000 tpy. Collectively, these
actions signify the sustained and growing importance of cement production in Utah throughout the
next century. Industry forecasters projectbetween 2 to 2.5 percent year growth in demand throughout
the United States, a rate which should easily be attained in Utah. With few substitutes, the cement
industry should remain strong over the longrun. Sold in ahighly competitive environment, however,
the industry may be subject to reorganizations, including mergers and acquisitions, which could
result in long term plant closures.
D. Soda Ash
Process Overview
Commercial soda ash (sodium carbonate) is used in numerous consumer products such as soap,
glass, detergents, paper, textiles, and food. About 75 percent of world production is synthetic ash
made from sodium chloride. The remainder is produced from natural sources. The United States
produces soda ash from natural sources exclusively.
Two methods are used to manufacture natural soda ash in the United States. The majority of
production comes from Wyoming, where soda ash is manufactured by calcination of trona ore in the
form of naturally occurring sodium sesquicarbonate. For every mole of soda ash created in this
reaction, one mole of C02 is also produced and vented to the atmosphere. The other process involves
the carbonation of brines; however, the C02 driven off in this process is captured and reused.
Once manufactured, most soda ash is consumed in glass and chemical production. Other uses include
water treatment, flue gas desulferization (FGD), and pulp and paper production. As soda ash is
processed for these purposes, additional C02 may be emitted if the carbon is oxidized. It is important
to realize, however, that there is limited availability of specific information about such emissions.
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Emissions Reduction Potential in Utah
C02 is released during production and consumption of soda ash. Soda ash is not produced in Utah;
however, consumption is reported by Dyce Chemical, a distributor of soda ash which is
manufactured outside of the state. Currently, Dyce is the sole distributor in the state and, according
to the firm, all resources are consumed within Utah.
For soda ash consumption, 113 metric tons of carbon is released for every 1,000 tons of soda ash
consumed in glass manufacturing or FGD. These latter two applications are deemed the most likely
markets for future consumption in Utah.
For the glass industry, soda ash is a source of sodium oxide used as a fluxing agent in container, flat,
fiber, and specialty glass manufacture to reduce the temperature at which the raw materials melt.
Soda ash decomposes into sodium oxide and C02, which rises through the glass melt and aids in the
mixing of all ingredients. Soda-rich glass is softer than other more refractory types of glass;
therefore, forming is easier. The quantity of soda ash added to glass batches varies with the type of
glass being manufactured and the percentage of recycled glass (also known as cullet) being used. The
growing nationwide effort to recycle glass has benefitted many of the 76 domestic glass-container
manufacturers because cullet substitutes for part of the raw material requirements in a glass batch,
and cullet melts at lower temperatures (about 20 to 25% less), thereby reducing glass production
costs. The increased use of cullet has conversely affected soda ash consumption. In 1988, the
national recycling rate for all glass containers was 22 percent; however, by 1992, the rate rose to 33
percent.
Soda ash also has potential applications for flue gas desulferization (FGD). FGD is a method to
reduce sulfur dioxide emissions in stack gases from the burning of fuel. Soda ash, and other soda
ash-based compounds such as sodium bicarbonate and sodium sesquicarbonate, are very effective
dry sorbents of sulfur and nitrogen compounds.
Compared to calcium-based compounds such as lime and limestone, soda ash-based scrubbing
reagents have been proven to be more effective scrubbers because of their greater surface area that
enhances the reaction with sulfur and nitrogen. However, soda ash remains more expensive and
geographically restrictive than calcium-based materials. Most of the power plants that burn high-
sulfur coal are located east of the Mississippi River where there are plentiful limestone quarries that
can be mined more economically and transported shorter distances than soda ash produced in the
West.
Finally, soda ash is increasingly used to chemically alter the pH of municipal and industrial water
supplies and as a precipitant to remove impurities in brine and industrial process water. In the basic
water treatment process, soda ash is added to adjust the acidity or alkalinity of water. Generally, it
is added to acidic water to raise the pH and reduce the corrosivity of the water and the accumulation
of mineral scale, thereby extending the life of metal pipes and equipment.
Because soda ash is not produced in Utah, there are no strategies associated with mitigation at this
level. Mitigation measures must therefore concentrate on the point of consumption. Clearly, resource
substitution is one strategy; however, there is no reliable data on the emissions saving from such
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strategies. One must assume, then, that reduction will stem from declines in output from those
industries which use soda ash directly.
Manufacturing output in Utah will likely remain strong across most industries. Accordingto the Utah
Greenhouse Gas Inventory, C02 from the manufacturing sector will grow at just under 4 percent per
year until 2010. Applying this growth rate to soda ash, one projects 608 tons of C02 by 2010. Any
reductions from this level will likely occur as a result of materials substitution or declines in
industrial output thereafter, though no accurate estimates can be made at this time.
II. Energy Sources
A. Oil and Natural Gas Production Processing
Natural gas may be released from the oil and gas system at several points, including oil wells, oil
refineries, natural gas wellheads, gas processing plants, and gas transmission and distribution
pipelines. Because methane is the principal constituent of natural gas (representing roughly 95
percent of the mixture) releases of natural gas lead to methane emissions.
Process Overview
As natural gas is extracted at the wellhead and moved to processing plants through gathering
pipelines, leakage from flanges, meters, and valves occur. Pneumatic valves, pressurized with natural
gas, will emit gas when reset. Natural gas also escapes when gathering pipelines are emptied for
maintenance. After the gas reaches the processing plant, emissions also occur as a result of leakage,
maintenance operations, and system upsets.
System upsets result from sudden pressure
spikes that prompt gas releases as a safety
measure or, failing this strategy, result in a
system rupture. Such events are uncommon in
the U.S. oil and gas system and contribute
only a fraction of total emissions.
Gas Transmission and Distribution
High-pressure transmission pipelines
transport natural gas from production fields
and gas processing facilities to distribution
pipelines. Pressure is lowered at gate stations
before it enters the local distribution system.
Natural gas may escape through leaky pipes
and valves and also through compressor
exhaust, while resetting pneumatic devices,
and during routine maintenance.
Table 6-3. Methane From Oil and Gas Production and
Transportation
Oil and Gas Production
Million Metric
Tons of Methane
Natural Gas Wellheads
0.30
Oil Wells
0.04
Gathering Pipelines
1.03
Gas Processing Plants
0.68
Heaters, Separators, Dehydrators
0.17
Total
2.23
Gas Venting
0.83
Gas Transmission Pipelines
2.17
Distribution Systems
1.48
Oil Refining and Transportation
0.08
Total
6.78
Source: Emissions of GHGs in the United States 1995.
Energy Information Administration. DOE/EIA - 0573(95).
October 1996.
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Oil Refining and Transportation
During the refining process, methane leaks occur when methane and oil are separated. When oil is
transferred to storage tanks at the refinery methane is emitted via vapor displacement. Methane not
destroyed during flaring operations will also be vented to the atmosphere. Vapor displacement
emissions occur during loading and unloading of oil barges and tankers as well.
Gas Venting
When an oil reservoir is developed for extraction there will often be associated natural gas produced
at the wellhead. If the flow of associated gas is too small or intermittent to be of value the gas will
be vented or flared. Associated gas with an insufficient heat content may also be vented or flared.
If a site lacks the necessary gathering and processing facilities for associated gas, that gas maybe
vented or flared. When flared, the methane content of natural gas is converted to C02; when vented,
the methane in natural gas is released directly to the atmosphere.
Emissions Reduction Potential
The Energy Information Administration (EIA) has compiled national statistics on methane emissions
from oil and gas operations. In Table 6-3 this data is calculated in million metric tons and organized
according to process or distribution.
As apparent from the table, oil and gas production and processing collectively accounts for one-third
of total fugitive emissions. Gas transmission and distribution accounts for over 50 percent. Oil
refining and transportation represent a mere 1 percent and gas venting just 12 percent. Overall, oil
operations represent only 2 percent of the total emissions in this category. As a result, mitigation
strategies should focus on natural gas operations.
According to the Utah GHG inventory, oil and gas production and distribution account for 1.3
million tons of GHG gases. Based on the percentage breakdowns above, gas transmission and
distribution account for 650,000 tons; oil and gas production and processing represents 430,000 tons;
oil refining and transportation translate into 13,000; and gas venting represents 160,000 tons.
Strategies include fixing leaks in valves, meters, and flanges for oil and gas production and
processing; recovering vented or flared gas where economically possible; repairing leaks in corroded
pipeline or inadequately sealed valves as well as in compressors and pneumatic devices.
By 2010, these emissions could reach 2.2. million tons of C02 equivalent. Assuming a sustained rise
in natural gas prices, the industry may seek efficiency improvements on the order of 5 to 10 percent,
translating into 100,000 tons saved by 2010.
B. Coalbed Methane
Process Overview
Methane and coal are formed simultaneously during the process whereby biomass is converted by
biological and geological forces into coal. The methane is stored in the pores (open spaces) of the
coal itself and in cracks and fractures within the coalbed. As coal is mined, the pressure surrounding
the stored methane decreases, allowing much of it to be released into the operating coal mine (in the
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case of an underground mine) or into the atmosphere (in the case of a surface mine). The methane
remaining in the coal pores is emitted as the coal is transported and pulverized for combustion. There
are several avenues for methane emissions from coal mines. Below are several of the more common
sources.
¦ Ventilation Systems in Underground Mines. Methane in concentrations over 5 percent is
explosive and presents a mortal danger to coal miners. To meet safety standards set by the
Mine Safety and Health Administration (MSHA), which require levels of methane
concentration to be maintained well below the 5 percent threshold, mine operators use
large fans to provide a steady airflow across the mine face and ventilate the mine shaft.
Typically, these ventilation systems vent substantial quantities of methane as part of fan
exhaust.
¦ Degasification Systems in Underground Mines. When the volume of gas in underground
mines is too high to be practically reduced to safe levels by standard ventilation
techniques, degasification systems are employed. Degasification may take place before
mining or may take the form of gob wells or in-mine horizontal boreholes. Methane
captured by degasification systems may be vented, flared, or recovered for energy. As of
1994, some 30 degasification systems were known to be operating in U.S.mines, with 10
mines recovering gas for energy use.
¦ Post-Mining Emissions. Methane that remains in coal pores after either underground or
surface mining will desorb slowly as the coal is transported (usually by train) to the end
user. Because coal that is consumed in large industrial or utility boilers is pulverized
before combustion, methane gas remaining in the coal pores after transport will be
released prior to combustion.
Emissions Reduction Measures
Depending on the fraction of coal that is produced by relatively large and gassy mines in a state,
encouraging utilization of coal mine methane can significantly reduce methane emissions. Methane
released from underground mines can be recovered and sold to pipeline companies or used as a feed
stock fuel to generate electricity for on-site use or for sale to off-site utilities. For pipeline sales, a
coal mine would need to install gathering lines to transport the methane to a commercial pipeline.
For power generation, a mine would need to install either an internal combustion engine or gas
turbine, both of which can be adapted to generate electricity from coal mine methane. Most methane
recovery and utilization technologies can be installed within a year.
Techniques for recovery include drilling wells before, during, or after mining. Wells drilled several
years in advance of mining will generally be the most expensive, but will recover large amounts of
nearly pure methane (up to 70 percent of the methane that would be otherwise emitted). W ells drilled
during or after mining can also recover substantial quantities of methane (up to 50 percent of
emissions), but the methane may be contaminated with mine ventilation air. While such a
methane/air mixture is normally suitable for power generation, inj ection into pipelines would require
enrichment of the gas, which may not be economically feasible.
Emissions Reduction Potential in Utah
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Methane gas from coal operations may be categorized as coal-bed methane (CBM) or coal-mine
methane (CMM). The former refers to methane associated with geological formations that contain
coal whereas the latter refers to methane associated with actual coal production.
The economics dictate that CMM is preferred to CBM for recovery in Utah. According to the Office
of Energy and Resource Planning, the majority of coal is produced in the Wasatch Plateau which
contains non-gassy coal methane gas in this field does not exceed 19 cubic feet per ton of coal
produced. By contrast, coal from the Book Cliffs is relatively gassy at about 451 cubic feet per ton
of coal produced. During 1998, the average emission from all Utah mines was 112 cubic feet per ton
of coal produced.
Methane recovery maybe pursued through either a pipeline or electric power project. The former
poses significant challenges due to the high cost of developing the necessary pipeline infrastructure
Table 6-4. Coalbed Methane Cost and C02 Reduction
Low Feasible or
Potential or
Best Estimate
High
Tons C02 reduced in 2010
181,483 207,409
233,335
Annualized $/ton C02 reduced in 2010
5 5
4
to move methane from the coal bed to a large trunk, commercial pipeline. In contrast, an electric
power project can more readily integrate with existing power transmission facilities.
A given mining operation would likely consider a CHP system, producing electricity for use and
resale and heat for a variety of thermal applications. For a 5 MW system, capital costs are estimated
at $3.6 million. Annual O&M costs and interest payments are further estimated at $773,665. Based
on a representative heat rate for a typical 5 MW facility, the methane input is estimated at 63.4
million Btu per hour. Three annualized cost estimates are provided below, representing capacity
factors of70, 80, and 90 percent respectively. Table 6A below provides this summary information.
III. Agricultural Sources
A. Fertilizer
Process Overview
Fertilizers, whether industrially synthesized or organic, add nitrogen to soils. Any nitrogen not fully
used by agricultural crops grown in these soils undergoes natural chemical and biological
transformations that can produce nitrous oxide (N20), a GHG. Scientific knowledge regarding the
precise nature and extent of nitrous oxide production and emissions from soils is limited. Significant
uncertainties exist regarding the agricultural practices, soil properties, climatic conditions, and
biogenic processes that determine how much nitrogen various crops absorb, how much remains in
soils after fertilizer application, and in what ways that remaining nitrogen evolves into nitrous oxide
emissions. Given these uncertainties, the challenge is to determine how to manipulate the nitrogen
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fertilizers and the time and manner in which these fertilizers are applied in order to minimize N20
emissions.
Emissions Reduction Strategies
The technical approached for reducing nitrous oxide emissions from fertilizers include improving
nitrogen-use efficiency in fertilizer applications. Improvements mean reducing excess fertilizer
application by applying only the amount crops will use, and replacing industrially-fixed nitrogen
fertilizers with renewable nitrogen source fertilizers.
Efficiency Improvements
All too frequently, more fertilizer is applied to a given site than can be effectively used by crops.
Further, poor timing or placement often leads to additional nitrogen loss or unavailability to the crop.
A major reason for excess application is the lack of simple field testing. In addition, many farmers
believe that some excess may be warranted to ensure peak production given the uncertainty
surrounding weather and climatic conditions.
While the direct relationship between fertilizer application rates and nitrous oxide emissions is not
well understood, current estimates suggest that better fertilization practices could reduce nitrogen
fertilizer use by as much as 20 percent with low risk of yield penalty and with possible input-cost
savings to farmers.
Nitrogen-use efficiency can be realized through any of seven management practices and three
specific fertilizer technologies. Several may be integrated into alternative agricultural systems that
incorporate lower fertilizer use and also achieve energy savings by reducing the need for plowing
and other energy intensive practices.
The following include specific management practices.
¦ Improve fertilizer application rate. Matching fertilizer application with specific crop
requirements would reduce excess fertilization, thus producing immediate GHG reduction
benefits. Soil testing, visual inspection, or plant tissue testing could allow farmers to apply
nutrients more closely by following crop requirements, rather than following broad
guidelines that often recommend excessive fertilization.
¦ Improve the frequency ofsoil testing. Due to its high cost, soil testing is usually conducted
once every two to five years. New technologies, such as the "Soil Doctor," combine soil
testing and fertilizer application in one system. The system has been shown to reduce
application rates by as much as 41 percent per acre, though at rather high cost.
¦ Improve timing of fertilizer application. Limited studies show that emissions from
fertilizer applied in the fall exceed those from fertilizer applied in the spring. With
improved understanding of these processes, and implications for crop production,
fertilizer timing could be adjusted to reduce GHG emissions.
¦ Improve placement of fertilizer. Surface placement and broadcasting can often result in
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excess or overlapping fertilizer application. Deep rather than superficial placement can
reduce nitrogen loss, though such placement may not be consistent with a no-till practice.
¦ Low-nitrogen fertilizer use. Switching from fertilizers with high nitrogen content,
particularly anhydrous ammonia, can reduce emissions. The rate of reduction, however,
is dependent upon farmers maintaining correct levels of application and not over-
compensating for the lack of ammonia found in the low nitrogen fertilizer.
¦ Conservation tillage. Alternative land tillage systems, such as low-till, no-till, and ridge-
till reduce soil losses and associated loss of nitrogen contained in the soil. Tillage
practices also affect the efficiency with which the fertilizer can be applied and
incorporated into the soil.
¦ Organic fertilizers. Organic fertilizers can be used to replace synthetic nitrogen fertilizers
where both are currently applied. With better knowledge of the nitrogen contents of
various organic fertilizers, farmers can use synthetic fertilizers as a supplement.
Technical approaches include:
¦ Nitrification inhibitors. Nitrification and urease inhibitors are fertilizer additives that can
increase nitrogen-use efficiency by decreasing nitrogen loss through volatilization.
Nitrification inhibitors can increase efficiency by around 30 percent in some situations.
¦ Fertilizer coatings. Limiting or retarding fertilizer water solubility through
supergranulation or by coating a fertilizer pellet with sulphur can double efficiency,
depending on the application.
¦ Reducing nitrogen release. Techniques that limit fertilizer availability, such as slow-
release or timed-release fertilizers, improve nitrogen-use efficiency by releasing nitrogen
at rates that approximate crop uptake. This reduces the amount of excess nitrogen
available at any given time for loss from the soil system. Slow-release fertilizer can
potentially decrease the number of applications, resulting in energy and cost savings.
Estimates of savings from the above practices are complicated by the challenge of projecting field-
by-field and crop-by-crop nitrogen requirements. As noted, some estimate that as much as 20 percent
of nitrogen may be reduced by determining the optimal combination of practices. To a large degree,
the modification of fertilizer practices is dependent on establishing the institutions and lines of
communicationbetween government agencies and farmers themselves to disseminate the knowledge
of new practices.
Given the long, steady decline in Utah's agricultural sector, the likelihood of instituting many of
these practices is low. Assuming that some practices will be adopted, one might assume that nitrogen
emissions could be reduced by 5 percent. Based on the 2010 forecast of 127,290 tons of C02
equivalents, this translated into a savings of 6,365 tons.
B. Methane Emissions from Domesticated Livestock
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Process Overview
The breakdown of carbohydrates in the digestive track of herbivores (including insects and humans)
results in the production of methane. The volume of methane produced from this process (enteric
fermentation) is largest in those animals that possess a rumen, or forestomach, such as cattle, sheep,
and goats. The forestomach allows these animals to digest large quantities of cellulose found in plant
material. This digestion is accomplished by microorganisms in the rumen, some of which are
methanogenic bacteria. These bacteria produce methane while removing hydrogen from the rumen.
The majority (about 90 percent) of the methane produced by the methanogenic bacteria is released
through normal animal respiration and eructation. The remainder is released as flatus.
The level of methane emissions from enteric fermentation in domesticated animals is a function of
several variables including: 1) quantity and quality of feed intake; 2) the growth rate of the animal;
3) its productivity (reproduction and/or lactation); and 4) its mobility. To estimate emissions from
enteric fermentation, the animals are divided into distinct, relatively homogeneous groups. For a
representative animal in each group, feed intake, growth rate, activity levels, and productivity are
estimated. An emissions factor per animal is developed based on these variables, which is then
multiplied by population data for that animal group to calculate an overall emissions estimate. The
method for developing these factors differs somewhat for cattle as opposed to all other animals.
Ruminants, which include cattle, buffalo, sheep and goats, have the highest methane emissions
among all animals due to their unique digestive system. Non-ruminant domestic animals, such as
pigs and horses, have much lower methane emissions than ruminants since much less methane-
producing fermentation takes place in their digestive systems. The amount of methane produced and
excreted by an individual animal depends upon its digestive system (whether or not it possesses a
rumen), and the amount and type of feed it consumes.
Table 6-5. Domesticated Livestock Emissions
Animal
Population
Methane Emissions
(tons)
C02 Equivalents
(tons)
Dairy Cattle
151,000
14,120.00
310,640.00
Beef Cattle
654,000
48,357.65
1,063,868.3
Buffalo
950
104.5
2,299.00
Sheep
440,000
3,872.00
85,184.00
Goats
2,129
11.71
257.62
Swine
40,000
66.00
1,452.00
Horses
34,778
688.6
15,149.2
Mules/Asses
565
13.7
301.4
Big game
232,260
6,012.00
132,264.00
Total
1,555,682
73,246.16
1,611,415.52
Source: Utah Greenhouse Gas Inventory.
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Because emissions from cattle account for about 96 percent of U.S. emissions from enteric
fermentation, they are given particular scrutiny. The U.S. cattle population is separated into dairy and
beef cattle. Dairy cattle are then divided into two categories of replacement heifers (0-12 months old
and 12-24 months old) and mature cows. Beef cattle are divided into six classes: 1) two categories
of replacements (0-12 months and 12-24 months); 2) mature cows; 3) bulls; 4) steers; 5) steers and
heifers raised for slaughter under the weanling system; and 6) steers and heifers raised for slaughter
under the yearling system.
Emissions Reduction Potential
In general, methane production by livestock represents an inefficiency because the feed energy
converted to methane is not used by the animal for maintenance, growth, production, or
reproduction. While efforts to improve efficiency by reducing methane formation in the rumen
directly have been of limited success, it is recognized that improvements in overall production
efficiency will reduce methane emissions per unit of product produced. A wide variety of techniques
and management practices are currently implemented to various degrees among livestock producers
which improve production efficiency and reduce methane emissions per unit of product produced.
Improving livestock production efficiency so that less methane is emitted per unit of product is
among the most promising and cost effective techniques for reducing livestock emissions. Specific
strategies for reducing methane emissions per unit product have been identified and evaluated for
each sector of the beef and dairy cattle industry. Throughout the industry, proper veterinary care,
sanitation, ventilation (for enclosed animals), nutrition, and animal comfort provide the basics for
improving livestock production efficiency. Within this context, a variety of techniques can help
improve animal productivity and reduce methane emissions per unit of product.
Table 6-6. Performance and Emission Factors for
Waste-to-Energy Project
Project MW (millions) 50
Cost per MW (million $) 2
Annual operations and maintenance cost
(thousands $) 100,000
MSW (tons) 500,000
Btus (millions) 5,000,000
MWh (generated) 350,400
MWh (sold)
V 7 297,840
C02 produced (tons) 245,280
Utility C02 avoided (tons) 122,745
Landfill C02 avoided (tons) 20,000
Net C02 Emissions (tons) 102,535
Landfill CH4 Avoided (tons) 7,008
Methane C02 equivalent (tons) 154,176
The existing systems for marketing milk and
meat products have important influences on
production efficiency and, therefore, methane
emissions. Refinements to the existing
marketing systems (fat versus protein pricing)
hold the promise of improving the link between
consumer preferences and production
decisions, thereby reducing waste and
improving efficiency.
Reduction Opportunities in Utah
In Utah, beef cattle account for 42 percent of
all domesticated animals and dairy cattle
represent 10 percent. Collectively, all other
domesticated animals (buffalo, sheep, goats,
swine, horses, and mules/asses) amount to 33
percent. Interestingly, the big game population
(15 percent) exceeds that of dairy cattle.
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Table 6-6 includes the 1993 statewide figures as well as the tons of methane associated with animal
population and specie. The last column is a conversion of methane to C02 equivalents, based on a
calculation of methane per head per year for each specie.
Based on emissions (C02 equivalents), the beef cattle industry represents two-thirds of all GHG
emissions. A distant second, the dairy cattle industry accounts for almost one in five tons.
Collectively, big game and all other animals, including non-ruminants, amounts to 15% of total
emissions.
Accounting for over half the total population of livestock, the dairy and beef cattle industries
represent the greatest opportunities for reducing methane emissions. For this reason, all reduction
strategies will focus exclusively on these industries.
Dairy Cattle Strategies
For the dairy industry, significant improvements in milk production per cow are anticipated in the
dairy industry as the result of continued improvements in management and genetics. Additionally,
production-enhancing technologies, such as bovine somatotropin (bST), are being deployed that
accelerate the rate of productivity improvement. By increasing milk production per cow, methane
emissions per unit of milk produced declines.
Dairy industry emissions can also be reduced by refinements in the milk pricing system. By
eliminating reliance on fat as the method of pricing milk, and moving toward a more balanced
pricing system that includes the protein or other non-fat solids components of milk, methane
emissions can be reduced. There is already a trend to reduce reliance on fat in the pricing of milk.
To realize methane emissions reductions from this trend, the effectiveness of alternative ration
formulations on protein synthesis must be better characterized.
Breeding options may also play an important role in reducing methane emissions. As the desirable
genetic characteristics of cattle change, the breed of cattle demanded by the dairy industry will also
change, possibly resulting in less cattle-related methane. In particular, the type of dairy cow that
would produce higher protein products under a protein-based pricing system would also emit less
methane.
To increase milk production per cow, the industry is currently using a growth hormone known as
bovine somatotropin (bST). By maximizing production per cow, overall emissions should decline
with increased use. However, the use of bST is somewhat controversial because of health and safety
concerns for both cows and humans.
Beef Cattle Strategies
Improving productivity within the cow-calf sector of the beef industry requires additional education
and training. The importance and value of better nutritional management and supplementation must
be communicated. Energy, protein, and mineral supplementation programs tailored for specific
regions and conditions need to be developed to improve the implementation of these techniques. The
special needs of small producers must also be identified and addressed.
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Refinements to the beef marketing system are needed to promote efficiency and shift production
toward less methane emissions intensive methods. To be successful, the refinements to the marketing
system require that the information flow within the industry be improved substantially. Techniques
are required to relate beef quality to objective carcass characteristics. Additionally, the carcass data
must be collected and used as a basis for purchasing cattle so that proper price incentives are given
to improve cattle quality and reduce unnecessary fat accretion.
Within the beef industry, several programs are underway to achieve these objectives. Carcass data
collection programs have been initiated that provide detailed data on carcass quality to participating
producers. Also, a major initiative is ongoing to educate retailers regarding the cost-effectiveness
of purchasing more closely trimmed beef (less trimmable fat). As these programs become more
widely adopted, the information needed to provide the necessary price incentives to producers will
become available.
Cow-calf productivity can potentially play a significant role reducing emissions. Increasing the rate
at which cows reproduce would reduce the number of breeding cows needed. In terms of methane
emissions, this is important because the breeding herd required to sustain the beef industry is
significantly larger than that in the dairy industry.
Ionophore feed additives provide yet another strategy for reducing emissions. These antibiotics are
mixed into feed to improve the efficiency of digestion and use. Ultimately, less feed per cow
translates into less methane per cow.
A final strategy consists of using anabolic steroid implants. These implants increase the rate of
weight gain in cattle, thereby decreasing the number of cows and the quantity of methane emissions
per unit of beef product.
In addition to these near term strategies, several long-term options may prove viable depending on
the success of ongoing research. These strategies include: 1) the transfer of desirable genetic traits
among species (transgenic manipulation); 2) the production of healthy twins from cattle (twinning);
and 3) the bioengineering of rumen microbes that can utilize feed more efficiently.
Competitive pressures to increase efficiency will encourage the dairy and beef industries to adopt
some or all of the short-term process changes described. Since 1950, however, the number of dairy
cattle in the United States has declined by over 50 percent, proving the dramatic impact that
production efficiency has had on the cattle industry. According to industry estimates, methane
emissions could be reduced by up to two percent per year if the above practices are employed. At
this rate, 284,577 tons of C02 equivalents could be reduced by 2010 for a total of 1,271,105 tons
emitted.
IV. Waste Management
A. Landfill Methane
Process Overview
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Landfills remain the largest single anthropogenic source of methane emissions in the US. Municipal
solid waste (MSW) landfills account for over 95 percent of landfill methane emissions, with
industrial landfills accounting for the remainder. Methane is produced during the bacterial
decomposition of organic material in an anaerobic (oxygen deprived) environment. The rate of
landfill methane production depends on the moisture content of the landfill, the concentration of
nutrients and bacteria, temperature, pH, the age and volume of degrading material, and the presence
and or absence of sewage sludge. Once produced, methane migrates through the landfill until a
vertical opening is reached and the gas escapes into the atmosphere.
Landfill gas produced in a sealed landfill can easily be captured by installing a gas recovery system.
Landfill gas is typically 50 percent methane and 50 percent C02. As a medium quality gas, it can be:
1) recovered, purified, and used to generate electricity; 2) used as a source of natural gas for
residential, commercial, or industrial heating needs; or 3) combusted in a flare. In addition there are
several emerging technologies that may be commercially available in the future, including using
landfill gas as a vehicle fuel or in fuel cell applications.
Gas recovery essentially involves the mining of trapped methane. The process consists of drilling
wells into the landfill, withdrawing the gas under negative pressure, and gathering the recovered gas
at a central processing center. As opposed to strategies focused on reducing the amount of
degradable waste landfilled (designed to curb future emissions), methane gas recovery reduces
current methane emissions. Recovering methane has other environmental and safety benefits as well,
such as reducing the risk of explosions, reducing odor, and reducing emissions of air toxics and non-
methane volatile organic compounds.
Landfill gas recovery projects have costs similar to those of relatively small renewable energy
technologies. Profitability depends on a range of factors, including the volume of recovered methane,
the price obtained for electricity or gas sales, and the availability of tax incentives. Currently, there
are more than 120 fully operational landfill projects in the United States, recovering approximately
64 Bcf gas. Nearly 80 additional projects are underway and the EPA has identified another 600
profitable gas recovery projects that are currently languishing due to information, regulatory, and
other barriers.
Landfill gas proj ects can provide many important environmental and economic benefits. The proj ects
improve the global environment by reducing methane emissions and benefit the local environment
by reducing emissions of volatile organic compounds (VOC), while simultaneously displaying
emissions associated with fossil fuel use. The projects also provide a secure, low-cost energy supply
that can reduce dependence on non-local energy and prevent waste of a premium energy source.
Finally, such projects can provide economic benefits, such as creating jobs and generating revenues.
Emissions Reduction Potential
There are several approaches to reducing MSW, thereby reducing landfill gas emissions. These
include reducing degradable wastes, recycling wastepaper products, and diverting waste to
incineration facilities.
Source reduction entails diverting waste before it enters the municipal waste stream. Reduction
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programs generally focus on incentives for reducing product packaging, and information campaigns
to promote bulk item purchase and composting.
Table 6-7. Annualized Cost of Waste-to Electricity Mitigation
Strategy
Low
Feasible or
Best Estimate
Potential
or High
Tons C02 reduced in 2010
134,904
154,176
173,448
Annualized $/ton C02
$47
$41
$36
reduced in 2010
Since organic wastes act as a substrate for methane-producing bacteria in a landfill, the recycling of
organic wastes such as paper and paperboard, wood waste, and food waste can significantly reduce
the amount of waste requiring landfill management. Recycled waste paper can also replace virgin
fiber sources and, in consequence, reduce timber harvesting levels and GHG emissions.
Finally, diverting solid waste to incineration facilities also reduces the amount ofMSW generated.
Unprocessed MSW can be diverted to a mass burn facility where the thermal energy from the
combustion is used to process steam, which can be sold directly to an institutional or industrial
customer, orusedto generate electrical power in a turbine. Alternatively, MSW maybe mechanically
processed into a more homogeneous refuse-derived fuel mixture. This mixture can be sold or burned
on-site to generate steam or electricity. Although C02 is produced upon waste combustion,
incineration saves between 0.5 and 0.6 tons of C02-equivalent per ton of refuse diverted relative to
landfill gas emissions.
Landfill Methane Recovery in Utah
According to information provided by the Utah Department of Environmental Quality, Division of
Solid and Hazardous Waste, the nine landfills that have or will soon have more than 1.1. million tons
of waste in place in Utah are Salt Lake County, Davis County, Cache County, Utah County, Weber
County, Washington County and Carbon County.
Though no large-scale recovery projects have been advanced to date in these counties, it is possible
to estimate levelized costs for a hypothetical project. A prime candidate, particularly for counties
with such high rates of growth, is a waste-to-electricity plant. The fundamental objective of such a
project is to extend the life of existing landfills and to reduce the requirements of future landfills.
Increasingly stringent environmental regulations will likely impose future constraints on the
additional development of landfills as well.
Economic analysis suggests a minimum flow ofMSW at200,000 tons per year to justify awaste-to-
electricity project. To give a sense of scale, such a flow would justify a 1 million ton in-place landfill
within 5 years unless such a recovery project is built. Costs per MW for such facilities average
around $2 million per MW. Annual operating and maintenance costs are estimated at approximately
$100,000 per MW assuming an 80% capacity factor.
Page 6-20
Part Six: Non-Fossil GHG Em issions
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Most projects are sized to process on the order of 500,000 tons per year, roughly equivalent to 1,400
tons per day. Table 6-6 provides the cost and emissions parameters for a representative project of
such scale.
Variability in MSW delivered can lead to changes in capacity factor. Though estimated at 80
percent, the project's capacity factor could range from as low as 70 percent to as high as 90
percent. The annualized costs for this range, and the estimated quantities reduced, are presented
in Table 6-7.
Note that these figures do not account for revenue generated from the potential sales of electricity.
B. Municipal Wastewater
Process Overview
Emissions of methane from the treatment of wastewater occurs when liquid waste streams containing
high concentrations of organic materials are treated anaerobically (in the absence of oxygen).
Anaerobic processes used in the US are anaerobic digestion, anaerobic and facultative (combining
aerobic and anaerobic processes), stabilization lagoons, septic tanks, and cesspools. Treatment of
wastewater solids using anaerobic is the most obvious potential source of methane emissions.
However, emission of significant quantities of methane from this process depends on the digester
gas being vented rather than recovered or flared. Anaerobic and facultative lagoons involve retention
of wastewater in impoundments where the organic materials in the wastewater undergo bacterial
decomposition.
The growth of algae, which absorb C02 and release oxygen as a result of photosynthesis, sustains
aerobic conditions at least near the surface of the lagoon. However, the bacteria deplete oxygen at
the bottom of the lagoon, producing conditions suitable for methanogenic bacteria. The extent of the
resulting anaerobic zone and the associated methane generation depend on such factors as organic
loadings and lagoon depth. In facultative lagoons, unlike anaerobic lagoons, a significant aerobic
zone persists.
Nearly 75 percent of US households are served by sewers that deliver domestic wastewater to central
treatment plants. Septic tanks or cesspools treat domestic wastewater from most of the remaining
households (24 percent). Anaerobic digestion is frequently used to treat sludge solids at US
municipal wastewater treatment plants. However, anecdotal evidence suggests that neither recovery
nor flaring of digester gas is common in the US, and equipment for recovery and flaring of such gas
is poorly designed or maintained, allowing most of the methane produced to be released to the
atmosphere.
Emissions Reduction Potential
Aerobic treatment requires less energy to operate and lower nutrient additions, and produces less
sludge; however, anaerobic treatment generally is more efficient, adapts to a wider volumetric load
range, and converts 40 to 60 percent of the emitted carbon into methane rather than C02. Although
this methane is reconverted to C02 when it is combusted, when used as a fuel, it can be used to
Part Six: Non-Fossil GHG Emissions
Page 6-21
-------
power a significant percentage of the sewage treatment system, and if refined into a liquid, can be
used to fuel vehicles.
While solids must be retained longer in anaerobic reactors due to slower biodegradation rates, the
necessary volume of the reactor vessel is smaller due to lower volumes of solids (due in turn to
anaerobic bacteria devoting most of their energy to producing methane). Perhaps the main negative
factors regarding anaerobic systems is the fact that anaerobic reactors cost about 10 percent more
than aerobic reactors. Further, in situations where secondary treatment is required, anaerobically
digested effluent generally requires further treatment before it can be discharged into receiving
waters. This process usually involves activated sludge in which solids are agitated with air or
oxygen. While activated sludge treatment is more efficient, its high energy costs make it more
expensive than other filtering methods. This higher cost can be offset somewhat by reusing methane
generated by the anaerobic phase(s) of treatment. This activity can have a large impact on overall
operating costs, since most of the energy used in a conventional wastewater plant goes to anaerobic
treatment.
Emissions Reduction Potential in Utah
In April 1999, the Salt Lake City Public Utilities department released an engineering feasibility study
for cogeneration facility sited at the Salt Lake City (SLC) Water Reclamation Plant located at 1530
South West Temple.
The SLC Water Reclamation Plant is a 56-million-gallon-per-day municipal wastewater treatment
plant located at 4,250 feet above sea level. Biological solids from the treatment process are stabilized
in four large, heated reaction vessels known as digesters. Within these digesters, anaerobic bacteria
flourish and produce combustible off-gas known as sewage digester gas.
Digester Gas
In 1998, the three 95-foot-diameter and one 100-foot-diameter digesters produced an average of
about 400,000 to 440,000 cubic feet per day of gas. This digester gas is normally about 55 to 65
percent methane and, about 35 to 45 percent C02, along with water vapor, nitrogen and small
amounts of other gases. One important other gas is noxious hydrogen sulfide (H2S), apparently now
present in the digester gas in concentrations of about 1600 to 3300 parts per million (ppm).
Digester gas is produced continuously and is currently burned in four large sewage sludge heaters
and two hot water boilers to warm the contents of the sludge digesters to their 98 degrees F operating
temperature. The boilers also provide the heating water necessary to warm buildings and tunnels at
the treatment plant. Excess digester gas, beyond that needed by the plant, is continuously burned off
in two new waste gas flares.
Energy Utilities
Electric power for the SLC Water Reclamation Plant motors, lights and equipment is purchased from
Utah Power and Light (UP&L). The plant is fed from two different 46-kilovolt (kV) incoming
Page 6-22
Part Six: Non-Fossil GHG Em issions
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electrical services for redundancy, as required by EPA regulations. Four UP&L electric meters serve
the SLC plant, but two and the pretreatment and main plants account for 99 percent of total electrical
consumption. Standby power for the pretreatment plant, about a mile away from the main treatment
plant, is provided by an 800-kilowatt (kW) and an 820-kW emergency generator. These standby
generators provide essential power to the influent pumps. The annual cost of electric power
Table 6-8. Summary of Recent Power Usage
Main Plant
Meter
(No.l)
Main Plant
Meter
(No. 2)
Pretreatment
Plant Area
(No. 1)
Pretreatment
Plant Area
(No. 2)
Year
1997 (1)
1998 (3)
(through May)
1997 (2)
1998 (3)
(through May)
Kilowatt hours (kWh)
9,713,600
3,555,200
3,176,000
1,616,000
Peak demand (kW)
1,328
1,184
N/A
720
Average usage (kW)
1,100
994
364
452
Ratio (average-to-peak
demand in percent)
83
84
N/A
63
Notes: 1. Based on a total of 368 days per 1997 billing months (or 8,832 hours)
2. Based on a total of 365 days in the 1997 billing months (or 8,760 hours)
3. Based on a total of 149 days in the first 5 months of 1998.
4. Total main plant and pretreatment plant average usage is 1,464 kW in 1997 and 1,446 kW in 1998.
Source: Salt Lake City Public Utilities communication. Dated 12 April 1999.
constitutes an important part of the cost of treatment plant operations. In 1997, SLC purchased
12,889,600 kilowatt-hours (kWh) of electric power from UP&L via thetwo largest plant meters. The
total cost of the UP&L power was $463,174 for an average cost of $0,036 per kWH. In 1997, the
yearly average electrical usage of the two larger meters was 1,464 kW.
Energy Resource
The 400,000 cubic feet per day of treatment plant digester gas is a significant energy resource. Based
on a digester gas heating value of 554 Btu per cubic fool lower heating value (LHV) as tested in
August 1998, this digester gas production has an equivalent fuel energy value of 9.23 million Btu
per hour (Btuh).
Power Generation Potential
Using a representative engine-generator fuel efficiency of 10,000 Btu per kWh (LHV), this 1998
SLC plant digester gas could be used to continuously generate an average electrical output of 923
kW.
Plant Heating Needs
The maximum quantity of heat needed for 98 degrees F digester operation is currently about 4
Part Six: Non-Fossil GHG Emissions
Page 6-23
-------
million Btuh. This is based on the four existing SLC treatment plant digesters, a raw sludge flow rate
of 115,000 gallons per day, and sludge thickened to 5.79 percent. This is also based on a minimum
wintertime raw sludge temperature of 52 degrees F (slightly less than the minimum January 1993
low sewage temperature at the nearby Central Valley WWTP, also in Salt Lake City).
The plant's first priority is to heat the anaerobic digesters. Currently only about 40 to 45 percent of
the 9.23 million Btuh fuel energy in the digester gas is needed to heat the raw sludge and the
digesters in the winter. Even less heat is required during the warmer weather.
If the digester gas is used to fuel engine generators with appropriate heat recovery equipment, then
adequate heat energy will be available all year for digester heating from the engine heat recovery
systems. In this scenario, all digester gas is piped to the CHP facility. Sufficient heat is available,
without supplemental natural gas, to heat the digesters using only the engine heat recovery system.
Existing Combined Heat and Power Facilities
In 1985, a CHP system was completed to burn the digester gas for electric power and heat for the
SLC plant operations. Facilities include three 300-kW generation units, together with engine heat
recovery equipment, digester gas compressors, piping, pumps, and electrical switchgear and
protective devices.
Planned Facilities
The SLC Public Utilities department is currently considering four options to address methane
recovery at the SLC Water Reclamation Plant. Table 6-9 provides detailed information on each
proposal.
Table 6-9. Economic Comparisons of Wastewater Methane Recovery Projects
Description
Alternative
A
Alternative
Bl
Alternative
B2
Alternative
C
Initial cost (construction,
contingency, and engineering)
$1,900,000
$1,300,000
$600,000
$800,000
Annual operating cost (1998 dollars)
$347,000
$441,000
$347,000
$556,000
Annual operating cost savings (1998)
$209,000
$115,000
$204,000
N/A
Simple economic payback (years)
9.1
11.3
9.1
N/A
Economic payback relative to the "no
CHP" diesel standby option (years)
5.3
4.3
5.3
N/A
Alternative A: (New system with two new 700-kW units)
Alternative Bl: (New system with one 700-kW unit now and one 700-kW unit in 4 years)
Alternative B2: (New system with one 700-kW unit now and one 700-kW unit in 4 years)
Alternative C: (Standby diesel engines only. No CHP)
Recommendations
Page 6-24
Part Six: Non-Fossil GHG Em issions
-------
Alternatives A, Bl, and B2 are the recommended CHP options. The alternative to select for
implementation depends upon SLC 's capital funding capability. The generators in these alternatives
would be designed for use with a low fuel pressure delivery system and with new heat recovery
equipment. The rationale is as follows:
Payback. The recommended alternatives would save SLC approximately $ 115,000 to $209,000 per
year, in 1998 dollars, for a simple payback of 9 to 11 years. Alternative A through B both have a 10-
year life-cycle cost of about $550,000 less than the "no CHP" option and a simple payback of about
5 years or less when compared to the "no CHP" option.
Financial Risk- Alternative B2 involves staging construction and capital expenditures. This option
involves less initial financial risk than the larger, more expensive Bl alternative.
Economic Hedge - Alternatives A and B1 would generate about 60 to 70 percent of the SLC Water
Reclamation Plant's 1998 electric power needs, thus providing economic insurance against any
future increases in power costs.
Air Quality - The recommended lean-burn engines would safely comply with no required air quality
standards. Moreover, the total annual exhaust emissions from the recommended alternatives would
be lower that the emissions from the existing waste gas burners and boilers.
Investment Recovery - The recommended CHP system allow SLC to recover the initial CHP
facility capital investment. Most of the original CHP facilities would be reused.
Waste Utilization - By converting a sewage byproduct to useful electric power, SLC will be sending
a strong positive message to the community. This resourcefulness, and the net reduction in air
emissions, represent important SLC commitments to the public and to the environment.
Schedule - Any of the recommendations (A to B2) couldbe operational within 18 to 24 months after
authorization.
Each of the CHP projects is designed to recover approximately 3,200 tons per year (roughly 71,000
tons of C02 equivalents).Table 6-11 below shows the levelized costs per ton (C02-equivalents) for
three levels of quantity reduced.
Table 6-10. Municipal Landfill Costs and Reduction
Low
Feasible or
Best Estimate
Potential
or High
Tons C02 reduced in
67,902
71,297
74,692
2010
Annualized $/ton C02
$7
$6
$6
reduced in 2010
Part Six: Non-Fossil GHG Emissions
Page 6-25
-------
Part Seven
Economic Impact of Selected Greenhouse Gas Mitigation Strategies
This report considered several policy options for reducing greenhouse gas mitigation strategies,
several of which involved energy-efficiency investment in end-use sectors. This section analyzes
the economic impact of 13 selected mitigation strategies in the Utah residential, commercial, and
industrial sectors. In particular, four strategies are considered for the residential sector, six
strategies are considered for the commercial sector and three strategies are considered for the
industrial sector. The premise of these greenhouse gas mitigation strategies is that investment in
energy efficiency - such as more efficient lighting, motors, or heating, ventilation, and air
conditioning (HVAC) - is prudent and more than pays for itself. Combined, these strategies are
estimated to reduce GHG emissions from natural gas by 122,296 C02 (1.2 percent) under the
feasible scenario and by 446,305 tons C02 (4.4 percent) under the potential scenario. In addition,
the strategies are estimated to reduce GHG emissions from electricity by 555,946 tons C02 (2.5
percent) under the feasible scenario and by 3,084,634 tons C02 (13.6 percent) under the potential
scenario. In total, the selected strategies could reduce Utah GHG emissions by 678,242 tons C02
in the feasible scenario and 3,530,939 tons C02 in the potential scenario.
Assuming a higher electricity price, investment in energy efficiency creates jobs and income growth
in the Utah economy. Nevertheless, any significant reduction in electricity use will have a negative
effect on the economy. The question, then, is what is the net effect? Do the benefits gained from
investment in end-use energy efficiency outweigh the losses in the electricity and natural gas sectors?
To answer this question, the Utah Multi-Regional Input-Output economic impact model was used
to determine the empirical consequences of selected greenhouse gas mitigation strategies.
Table 7-1 outlines in broad detail the effect
on the Utah economy of the investment in TahlL' 7_l- Assessing the Effect on the Utah Economy
energy efficiency and the reduction in
electricity use. All other considerations
equal, then, the reduction in electricity and
natural gas use has a negative effect on the
economy. This is asserted qualitatively in
Table 7-1 and empirically estimated in the
following section. Similarly, all other considerations held constant, then the investment in energy
efficiency has a positive effect on the economy. This is also asserted qualitatively in Table 7-1 and
then empirically estimated in the following section. Overall, the combination of the two action
programs has an unknown net effect. The Utah Multi-Regional Input-Output model is ideally suited
to analyze a problem such as this. The "Economic Base" version for the Utah statewide model was
chosen to offer empirical evidence.
Selected end-use residential, commercial, and industrial sector mitigation strategies are identified
along with fundamental assumptions concerning the effectiveness and implementation or success
rates. While the 13 end-use investment strategies represent only a subset of all of the strategies
Action
Effect on Net
Utah Economy Effect
Reduction in electricity natural gas
use Negative
Investment in energy efficiency
Positive
Combination of above
+/- ?
Part Seven: Economic Impact of Selected Greenhouse Gas Mitigation Strategies
Page 7-1
-------
considered earlier in this report, they represent a significant diversification of investment strategies.
In addition, the expenditures on labor and materials to implement each of these strategies are
identified and described. Finally, economic impact results are presented not only for investment in
Table 7-2. Residential Sector Investment Assumptions
Percent
Simple
Feasible
Potential
Strateav Activity
Savings
Payback
Implementation
Implementation
Lighting retrofit Lighting
40%
4
10%
80%
Fuel switching Water Heating
50%
6
3%
20%
High-efficiency refrigerator Appliance
20%
11
5%
80%
Weatherization Heating, Cooling
30%
10
10%
70%
Table 7-3. Commercial Sector Investment Assumptions
Percent
Simple
Feasible
Potential
Strategy
Activ ity
Savings
Payback
Implementation
Implementation
Lighting retrofit
Lighting
25%
6
15%
95%
Lighting controls
Lighting
10%
7
10%
75%
HVAC control systems
Total Building
12%
13
10%
50%
Building commissioning
Total Building
10%
1
10%
75%
Variable-speed drive
Total Building
6%
12
5%
35%
Plug loads
Total Building
5%
1
25%
75%
energy efficiency but also for the reduction in the electric and natural gas service industries.
The Strategies in Detail
The residential sector investment assumptions are given in Table 7-2. Strategies cover high-
efficiency lighting, fuel switching (electric-to-gas water heaters), premium efficiency refrigerators,
and weatherization. These four strategies were chosen as examples of four broad areas of residential
end-use energy efficiency improvement: lighting, fuel switching, large appliances, and total building
aspects. These strategies are intended to improve the end-use efficiency of electricity and natural
gas. Percent savings range from 20 to 50 percent. Payback in years ranges from 4 to 11 years.
Feasible implementation or success rates range from 3 to 10 percent, while potential implementation
or success rates range from 20 to 80 percent.
The commercial sector investment assumptions are given in Table 7-3. Two strategies cover
Table 7-4. Industrial Sector Investment Assumptions
Percent
Simple
Feasible Potential
Stratesv Activity
Savings
Pavback
Implementation Implementation
Lighting retrofit Lighting
15%
3
60% 95%
Steam system optimization Heating, Process Heating
30%
4
15% 30%
Motors HVAC and Processes
18%
2
50% 95%
Page 7-2
Part Seven: Economic Impact of Selected Greenhouse Gas Mitigation Strategies
-------
lighting, while the remaining four strategies cover total building aspects. The six strategies are 1)
high-efficiency lighting retrofit; 2) lighting control systems; 3) HVAC control systems; 4) building
commissioning or recommissioning; 5) variable-speed drive motors; and 6) plug loads. These
strategies are intended to improve the end-use efficiency of electricity and natural gas. Percent
savings range from 6 to 25 percent. Payback in years is as low as 1 year to 13 years. Feasible
implementation or success rates range from 5 to 25 percent, while potential implementation or
success rates range from 35 to 95 percent.
The industrial sector investment assumptions are given in Table 7-4. These strategies cover lighting,
HVAC, and processes and are all intended to improve the end-use efficiency of electricity and
natural gas. The three strategies are 1) high-efficiency lighting retrofit; 2) steam system
optimization; and 3) motors. Percent savings
Table 7-5. Feasible strategy Average Annual range from 15 to 30 percent. Payback in years
Employment ranges from 2 to 4 years. Feasible
implementation or success rates range from 50
to 60 percent, while potential implementation
or success rates range from 30 to 95 percent.
Economic Impact Results
Economic impact results for both feasible and
potential strategies are presented for the State
of Utah as a whole and by major economic
sector. Sectors are agriculture, mining,
construction, manufacturing, TCPU, wholesale
trade, retail trade, FIRE, services, and
government. TCPU is short for transportation,
communications, and public utilities. FIRE is
short for financial, insurance, and real estate.
The economic impact model presents
employment and earnings impacts. These are
shown in the accompanying tables as "Change
in Employment" or "Change in Earnings,"
along with a percent change from the 1998
baseline.
Feasible Strategies
The average annual economic impact on
employment of the feasible strategies is shown
in Table 7-5. The feasible strategies generate
an average of482 new jobs each year. Mining,
TCPU, and government showed losses. All other sectors had positive job growth. For the feasible
strategies, the absolute value of the percent change is less than 0.1 percent in all sectors.
Employment
Change in
Percent
Baseline
Employment
Change
Agriculture
26,404
5
0.02%
Mining
9,592
(9)
-0.09%
Construction
72,124
74
0.10%
Manufacturing
130,170
33
0.03%
TCPU
55,519
(48)
-0.09%
Wholesale Trade
49,995
43
0.09%
Retail Trade
197,724
164
0.08%
FIRE
81,034
35
0.04%
Services
308,717
206
0.07%
Government
163,666
(28)
-0.02%
Total
1,100,273
482
0.04%
Table 7-6. Feasible Strategy Average Annual Earnings
(in thousand dollars)
Earnings
Change in
Percent
Baseline
Earnings
Change
Agriculture
$583,270
$119
0.02%
Mining
$441,747
($447)
-0.10%
Construction
$2,239,843
$2,295
0.10%
Manufacturing
$4,258,334
$862
0.02%
TCPU
$2,157,426
($3,386)
-0.16%
Wholesale Trade
$1,587,558
$1,362
0.09%
Retail Trade
$3,014,582
$2,394
0.08%
FIRE
$2,475,541
$1,119
0.05%
Services
$7,965,133
$4,805
0.06%
Government
$4,367,555
($609)
-0.01%
Total
$29,135,687
$8,561
0.03%
Part Seven: Economic Impact of Selected Greenhouse Gas Mitigation Strategies
Page 7-3
-------
The average annual economic impact on earnings of the feasible strategy is shown in Table 7-6. The
feasible strategies generated an average of almost $8,600,000 in new earnings each year. As
expected, the energy-efficiency strategies result in a reduction of some electric and natural gas
services jobs and earnings.
The special trades construction, wholesale trade, and architectural and engineering services show the
largest increase in earnings and employment.
Other sectors, however, benefit from this type
of program as well. It is important to note that
since the economic impacts represent average
annual impact, they apply to each year of the
program.
Potential Strategies
The average annual economic impact on
employment of the potential strategies is shown
in Table 7-7. The potential strategies generate
an average of 1,623 new jobs each year. Again,
mining, TCPU, and government showed losses.
All other sectors had positive job growth. For
the potential strategies, the absolute value of the percent change is less than 0.5% in any of the
sectors. TCPU again experience the largest reduction in employment.
The average annual economic impact on earnings of the potential strategies is shown in Table 7-8.
The potential strategies generated an average of almost $24,058,000 in new earnings each year. As
expected, the energy-efficiency strategies result in a reduction of some electric and natural gas
services jobs and earnings. It is interesting to note the connection between the mining and utility
sectors. In addition to TCPU, the mining sector also experiences a slight reduction in jobs.
The special trades construction, wholesale
trade, and architectural and engineering
services show the largest increase in earnings
and employment. Other sectors, however,
benefit from this type of program as well. It is
important to note that since the economic
impacts represent average annual impact, they
apply to each year of the program.
Economic Impact Model Assumptions
An economic impact model is a quantitative
representation of a local economy. The
primary strength of these models is that they
Table 7-7. Potential Strategy Average Annual
Employment
Employment
Baseline
Change in
Emplovment
Percent
Chanse
Agriculture
26,404
18
0.07%
Mining
9,592
(41)
-0.43%
Construction
72,124
300
0.42%
Manufacturing
130,170
117
0.09%
TCPU
55,519
(280)
-0.50%
Wholesale Trade
49,995
200
0.40%
Retail Trade
197,724
603
0.30%
FIRE
81,034
127
0.16%
Services
308,717
764
0.25%
Government
163,666
(205)
-0.13%
Total
1,100,273
1,623
0.15%
Table 7-8. Potential Strategy Average Annual Earnings
(in thousand dollars)
Earnings
Change in
Percent
Baseline
Earninss
Chanse
Agriculture
$583,270
$432
0.07%
Mining
$441,747
($2,181)
-0.49%
Construction
$2,239,843
$9,298
0.42%
Manufacturing
$4,258,334
$2,933
0.07%
TCPU
$2,157,426
($19,033)
-0.88%
Wholesale Trade
$1,587,558
$6,349
0.40%
Retail Trade
$3,014,582
$8,825
0.29%
FIRE
$2,475,541
$4,000
0.16%
Services
$7,965,133
$17,923
0.23%
Government
$4,367,555
($4,663)
-0.11%
Total
$29,135,687
$24,058
0.08%
Page 7-4
Part Seven: Economic Impact of Selected Greenhouse Gas Mitigation Strategies
-------
capture many of the inter-industry linkages that exist in the economy. The economic impact model
captures the "ripple effect" caused by expenditures made in one sector of the economy and yield
estimates of economic "multipliers." The economic effect of the energy efficiency investment
program is the sum of the direct, indirect, and induced effect. The direct effect consists of the
program costs. The indirect effect results from, for example, construction and wholesaler purchases
made during the course of the program from their suppliers. The induced effect is the economic
activity generated as dollars are circulated throughout the broader economy.
It is inevitable that there are several assumptions made in this type of analysis. These important
assumptions are listed below and briefly described.
1) Above all, it is assumed that the fundamental economic linkages in the model remain fixed over
time and do not change due to the exogenous investment in energy efficiency.
2) Since an economic impact model is best suited to analyze a small, exogenous change in the
economy, extending this model to an assessment of the relatively large change required by
greenhouse gas mitigation strategies would be beyond the appropriate use of the economic impact
model. Therefore, we have stylized the assessment to two fundamental components of the mitigation
strategies assessed in this report: 1) investment in energy efficiency in the residential, commercial,
and industrial sectors; and 2) a reduction in electricity and natural gas demand and its result on the
electricity and natural gas services sectors.
3) It is assumed that the reduction in electricity and natural gas consumption has an effect on the
electric and natural gas services sectors. Because of fixed costs associated with electricity and
natural gas infrastructure, the effect on the electric power and natural gas sectors was assumed to be
less than the respective percent reduction in consumption for each fuel.
4) Other assumptions are inherent within the economic impact framework. The purchases made
from the wholesale trade industry, for example, are scaled down to 20 percent. In addition, because
building operators are likely to spend much of the net annual savings that stem from energy
efficiency retrofits in the Utah economy, 80 percent of these savings were assumed to return to the
economy in the form of increased consumption. This is assumed to be the fixed margin for the
wholesaler. Economic impact analysis is a static or "snapshot" analysis. That is, the economic
impact model estimates the effect of earnings and employment associated with a program, holding
all else constant. Furthermore, the economic impact model does not and cannot address how an
economy will adjust to this program. Nevertheless, even with the inherent assumptions and
limitations, economic impact analysis provides a credible representation of an effect of a program.
Part Seven: Economic Impact of Selected Greenhouse Gas Mitigation Strategies
Page 7-5
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Part Eight
Conclusion
Conclusions and Discussion
The most casual observer of current events cannot fail to notice the heightened attention devoted to
the global issue of greenhouse gas emissions. Accounts of the issue's potential effects on the
population and natural environments occupy our evening news and grace the editorial pages with
increasing frequency. Indeed, barely a month passes without the media confirming long held
suspicions that human activity contributes measurably to the Earth's warming. Seemingly, with each
new report, yet another mind in the scientific community is won over and the public's attention is
riveted once again.
It has been in the spirit of this growing scientific and public consensus that the Division of Air
Quality (DAQ) and the Office of Energy and Resource Planning (OERP) has undertaken this
research. Along with Phase I, the Utah Greenhouse Gas Inventory cited frequently in this study,
Phase II marks the state's initial steps toward both the identification of GHG sources and the
economic assessment of various GHG mitigation strategies. Specifically, it is the purpose of this
study to prepare and analyze realistic policy options for reducing GHG emissions in Utah.
As noted, per capita emissions in Utah are nearly twice that of the U.S. average and the State
produces significant amounts of energy for domestic use and the export market. Therefore, Utah
stands to benefit tremendously from cost-effective future energy savings and associated emissions
reduction. In many scenarios, the state has a unique opportunity to strengthen and diversify its
economy while reducing carbons dioxide emissions and other pollutants.
This study provides engineering-economic analyses of a combination of energy efficiency and
renewable energy initiatives. The research includes several options for reducing GHG emissions
(carbon dioxide, methane, and nitrous oxide). These options may be ranked according to several
criteria including cost, quantity reduced per measure (feasible and potential), or political or
institutional feasibility. This research attempts to identify those measures for which the largest
quantities of carbon dioxide are reduced, at the least cost, and with the highest degree of
administrative feasibility and public receptivity.
As shown in Figure 8-1, on average, the mitigation strategies in the transportation and commercial
sectors had the highest emissions reduction capacity. Unfortunately, as shown in Figure 8-2,
transportation sector mitigation strategies tended to have the highest cost per ton C02 reduced.
Because of their combination of high emissions reduction capacity and low cost, commercial sector
mitigation strategies represent some of the most efficient options for achieving meaningful GHG
reductions.
Part Eight: Conclusion
Page 8-1
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Figure 8-1. GHG Mitigation Strategies
Emissions Reduction
3,000
o
o
5,000
4,000
.8
H
2,000
$160
$140
$120
$100
I $80
i L
Residential
X
Commercial
Industrial
Sector
T ransportation
| | Feasitile | | Potential
Total
Figure 8-2. GHG Mitigation Strategies
Cost
$60
$40
$20
$0
Residential
Commercial
Industrial
Sector
Transportation
Total
| | Feasible | | Potential
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Part Eight: Conclusion
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In terms of political or institutional feasibility, there is wide variation across the many measures in
each sector. By far, demand-side management programs sponsored by utilities have the longest
history of application in each of the residential, commercial, and industrial sectors. Energy efficiency
measures, undertaken by firms and households, are also well entrenched, popular programs.
Electricity supply technologies such as cogeneration and wind power have also enjoyed legislative
support at federal and state levels for over two decades. This support will likely continue for utility-
sponsored net metering, green pricing, and renewable portfolio programs. The greatest institutional
hurdles, however, will likely affect the transportation sector. Fuel conversion programs will probably
experience little resistance and even garner support in the years to come. However, large-scale and
capital-intensive projects such as light-rail extension or heavy-rail, long-distance projects will likely
encounter significant opposition and challenges.
Finally, it must be emphasized that many of the measures described herein provide "no regrets" by
offering externality benefits not directly accounted for in the cost per ton calculations. For example,
Utahns stand to benefit from cleaner air beyond the specific reduction of GHGs. Perhaps more
importantly, the pursuit of GHG mitigation programs will greatly strengthen and diversify the Utah
economy by providing firms and households with energy cost savings and, potentially, greater
employment opportunities through a burgeoning energy efficiency industry.
The Role of Government Agencies and Institutions
Beyond describing the relative costs of mitigation measures, no explicit recommendations are
formed regarding which measures or bundles of measures should logically be implemented. It is
expected, however, that many different institutions and government agencies will ultimately be
responsible for promoting measure adoption.
Federal Actions
The U.S. Senate's early ratification of the UN treaty in October 1992, and the release of the
President's Climate Change Action Plan in October 1993, underscore the U.S. commitment to a
National policy on global climate change that is consistent with the UN treaty. The plan consists of
a two-fold strategy to commit the Nation to reducing GHGs and establish a national research agenda
to enhance knowledge in areas relevant to climate change.
The national action plan essentially calls for reducing emissions to 1990 levels by the year 2000
through cost-effective domestic actions alone. Nearly 50 new or expanded initiatives encompassing
all GHGs and all sectors of the economy are outlined in the plan. These voluntary programs
emphasize public and private cooperation and are designed to reduce energy intensity and/or
stimulate markets for new technologies. The national plan also includes the U.S. Initiative on Joint
Implementation, which is a pilot program to foster experience in evaluating investments to reduce
emissions in other countries.
Aside from its pivotal role in establishing the Climate Change Action Plan, and motivating state-
level research on mitigation strategies, the federal government figures prominently in the support of
many potential GHG reduction strategies. In the residential sector, for example, federal standards
regarding appliance efficiency are key strategies for limiting emissions. Similar efficiency standards
may also apply to equipment used in the commercial sector such as lighting and HVAC systems. In
Part Eight: Conclusion
Page 8-3
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addition, the federal government sponsors a number of conservation programs such as Green Lights,
which promotes energy efficient lighting systems. The industrial sector benefits as well from federal
programs such as Motor Challenge and Steam Challenge.
It is difficult to overestimate the importance of the federal government's role in funding research and
development that promotes efficient energy supply sources and end-use applications. Funding
support and grants from the U.S. Department of Energy (DOE) and EPA are largely responsible for
efficiency gains in various technologies such as solar, wind, biomass, and fuel cells. Perhaps more
importantly, the federal government has offered tax incentives for several technologies over the past
two decades.
In addition to technical and financial support, the federal government would likely assume the lead
role, if necessary, in instituting market-related measures such as emissions cap-and-trade, carbon
taxes, or command-and-control of GHG reduction.
State Actions
It is at the state level where most mitigation strategies will likely be identified and implemented. It
is the general conviction of federal agencies that state governments are better prepared to
simultaneously undertake the complex analyses of various measures and evaluate the political and
institutional feasibility of implementing specific measures.
In Utah, state agencies such as the Division of Public Utilities (DPU) and the Public Service
Commission (PSC) have long advocated energy efficiency practices. In compelling investor-owned
utilities to offer DSM programs, state government policies have directly provided Utah's households,
commercial businesses and industries with varied opportunities for saving on energy bills while
improving the environment.
In addition to supporting DSM programs, state agencies have long championed supply-side strategies
such as independent power projects, distributed generation, and cogeneration.
State government policies may have the greatest impact for GHG reduction in the transportation
sector. Laws and regulations at the state level are necessary for establishing a number of mitigation
strategies including vehicle fuel conversion and supporting infrastructure, tire inflation, enhanced
I&M inspection, land-use planning, speed enforcement, traffic regulation, and mass transit projects.
Of note, some of these strategies are currently being adopted by Utah.
Local Actions
Typically, local and city governments have neither the legislative latitude nor the taxing authority
to promote a wide range of mitigation measures. To a larger extent, however, energy efficiency
strategies adopted by municipalities frequently overlap with those advanced by state governments.
Municipalities, for example, often host public utilities which generally offer DSM services to most
customer classes. In addition, some utilities in Utah have sponsored renewable energy technology,
most notably a wind project located in Spanish Fork sponsored by Utah Municipal Power Agency
(UMPA).
Local governments promote a number of conservation programs in the transportation sector
(alternative fuels, rideshare, telecommuting). States, in contrast, are at the center of most laws
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Part Eight: Conclusion
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regarding transportation efficiency including feebates, consumption taxes, and land-use planning.
Local governments are generally limited to supporting traffic improvements, speed limits, and
funding for mass transit projects such as Salt Lake City's light-rail project.
Individual and Firm Actions
Household actions to limit GHG emissions are defined in this report as the willingness to participate
in utility or government-sponsored energy efficiency programs and to abide by laws such as speed
limits and vehicle inspections. Voluntary actions such as lowering energy consumption, the cost of
which is borne by the consumer, are also considered to be crucial in gaining the maximum amount
of emissions reductions.
Firm-related actions are also dependent on participation in energy efficiency programs, including
actions such as telecommuting. In the case of energy-producing firms, such as electric utilities, there
are additional actions that have profound consequences for energy reduction. One example is the
strategic business decision of utilities to mothball coal-fired facilities or convert them to partial or
full use of natural gas.
Concluding Remarks
Phase II of this research demonstrates that meaningful reductions in GHG emissions could be
achieved at reasonable costs. In addition, the results of preliminary economic impact analyses
suggest that these costs may be offset - or even overwhelmed — through savings and external
benefits generated by efficiency improvements to our residential, commercial, and industrial energy
infrastructure. Still larger reductions in GHG emissions may likely require additional research and
the development of new mitigation technologies and strategies. Regardless of which strategies - if
any - are selected, it is clear from this research that solutions to the problem of rising GHG
emissions will be cross-sectoral in nature and will necessitate cooperation among several public and
private institutions.
Part Eight: Conclusion
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