text:
Arizona Public Service Company
Salt River Project
Tucson Electric Power Corporation
Arizona Renewable Energy Assessment
B& V Project Number 145888
September 2007
Black & Veatch Corporation
11401 Lamar
Overland Park, Kansas 66211
Tel: ( 913) 458- 2000 www. bv. com
Principal Investigators:
Ryan Pletka, Project Manager
Steve Block
Keith Cummer
Kevin Gilton
Ric O'Connell
Bill Roush
Larry Stoddard
Sean Tilley
Dave Woodward
Matt Hunsaker
GeothermEx – Subcontractor for geothermal sections
© Copyright, Black & Veatch Corporation, 2007. All rights reserved.
The Black & Veatch name and logo are registered trademarks of
Black & Veatch Holding Company
Arizona Renewable Energy Assessment Table of Contents
21 September 2007 TC- 1 Black & Veatch
Table of Contents
1.0 Executive Summary ................................................................................................... 1- 1
1.1 Background and Objective................................................................................... 1- 1
1.2 Renewable Energy Technology Options ............................................................. 1- 2
1.3 Renewable Resource Assessment ........................................................................ 1- 2
1.3.1 Direct Fired and Cofired Biomass .............................................................. 1- 3
1.3.2 Landfill Gas ................................................................................................ 1- 4
1.3.3 Anaerobic Digestion ................................................................................... 1- 4
1.3.4 Solar Thermal Electric ................................................................................ 1- 4
1.3.5 Solar Photovoltaic....................................................................................... 1- 5
1.3.6 Hydroelectric............................................................................................... 1- 6
1.3.7 Wind Power ................................................................................................ 1- 6
1.3.8 Geothermal.................................................................................................. 1- 7
1.4 Forecasted Renewable Energy Development ...................................................... 1- 7
1.5 Assessment of Key Risk Factors........................................................................ 1- 10
1.5.1 Tax Credit Changes................................................................................... 1- 11
1.5.2 Advanced Solar Technologies .................................................................. 1- 11
1.5.3 Delayed Technical Advances.................................................................... 1- 11
1.5.4 Escalating Construction Costs .................................................................. 1- 11
1.5.5 Manufacturing and Supply Chain Constraints.......................................... 1- 12
1.5.6 Near Term Performance Learning Curve / Project Failure....................... 1- 12
1.5.7 Competition for Limited Resources.......................................................... 1- 12
2.0 Introduction................................................................................................................ 2- 1
2.1 Background.......................................................................................................... 2- 1
2.2 Objective .............................................................................................................. 2- 1
2.3 Approach.............................................................................................................. 2- 2
2.4 Report Organization............................................................................................. 2- 3
3.0 Renewable Energy Overview .................................................................................... 3- 1
3.1 Historical Development of Renewable Energy.................................................... 3- 2
3.1.1 1978- 1991: PURPA and Standard Offer Contracts .................................... 3- 3
3.1.2 1992- 2004: The PTC and RPS Era ............................................................. 3- 5
3.1.3 2005: Energy Policy Act............................................................................. 3- 6
3.2 Renewable Energy Status in Arizona .................................................................. 3- 8
3.2.1 Existing and Announced Renewable Energy Projects.............................. 3- 10
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3.2.2 Arizona Renewable Energy Standard ....................................................... 3- 10
4.0 Assessment of Renewable Energy Technology Options ........................................... 4- 1
4.1 Introduction.......................................................................................................... 4- 1
4.1.1 Technologies Evaluated .............................................................................. 4- 1
4.1.2 General Approach to Characterization........................................................ 4- 2
4.1.3 Levelized Cost of Energy Calculation Example......................................... 4- 3
4.2 Solid Biomass ...................................................................................................... 4- 5
4.2.1 Direct- Fired Biomass .................................................................................. 4- 5
4.2.2 Biomass Gasification and IGCC................................................................. 4- 9
4.2.3 Biomass Cofiring ...................................................................................... 4- 12
4.2.4 Plasma Arc Gasification ........................................................................... 4- 16
4.2.5 Biomass Technologies Development Prospects ....................................... 4- 19
4.3 Biogas ................................................................................................................ 4- 24
4.3.1 Anaerobic Digestion ................................................................................. 4- 24
4.3.2 Landfill Gas .............................................................................................. 4- 28
4.4 Solar Electric...................................................................................................... 4- 31
4.4.1 Solar Thermal Power ................................................................................ 4- 31
4.4.2 Photovoltaics............................................................................................. 4- 39
4.4.3 Solar Technologies Development Prospects............................................. 4- 46
4.5 Hydroelectric...................................................................................................... 4- 48
4.6 Wind Power ....................................................................................................... 4- 55
4.7 Geothermal......................................................................................................... 4- 60
4.8 Fuel Cells Using Renewable Fuels .................................................................... 4- 64
4.9 Compressed Air Energy Storage........................................................................ 4- 67
4.10 Renewable Energy Technology Summary....................................................... 4- 69
4.10.1 Relative Costs ......................................................................................... 4- 71
4.10.2 Recommendations for Further Study ...................................................... 4- 71
5.0 Renewable Resource Assessment .............................................................................. 5- 1
5.1 Direct Fired and Cofired Biomass ....................................................................... 5- 1
5.1.1 General Methodology ................................................................................. 5- 1
5.1.2 Major Assumptions..................................................................................... 5- 4
5.1.3 Future Cost and Performance Projections................................................... 5- 6
5.1.4 Data Sources ............................................................................................... 5- 7
5.1.5 Projects Identified ....................................................................................... 5- 7
5.2 Landfill Gas ....................................................................................................... 5- 10
5.2.1 General Methodology ............................................................................... 5- 10
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5.2.2 Major Assumptions................................................................................... 5- 12
5.2.3 Future Cost and Performance Projections................................................. 5- 13
5.2.4 Data Sources ............................................................................................. 5- 13
5.2.5 Projects Identified ..................................................................................... 5- 13
5.3 Anaerobic Digestion .......................................................................................... 5- 16
5.3.1 General Methodology ............................................................................... 5- 16
5.3.2 Major Assumptions................................................................................... 5- 17
5.3.3 Future Cost and Performance Projections................................................. 5- 17
5.3.4 Data Sources ............................................................................................. 5- 17
5.3.5 Projects Identified ..................................................................................... 5- 18
5.4 Solar Thermal Electric ....................................................................................... 5- 21
5.4.1 General Methodology ............................................................................... 5- 21
5.4.2 Major Assumptions................................................................................... 5- 22
5.4.3 Future Cost and Performance Projections................................................. 5- 23
5.4.4 Data Sources ............................................................................................. 5- 26
5.4.5 Projects Identified ..................................................................................... 5- 26
5.4.6 Parabolic Dish Stirling Assumptions........................................................ 5- 28
5.5 Solar Photovoltaic.............................................................................................. 5- 31
5.5.1 General Methodology ............................................................................... 5- 32
5.5.2 Major Assumptions................................................................................... 5- 32
5.5.3 Future Cost and Performance Projections................................................. 5- 32
5.5.4 Data Sources ............................................................................................. 5- 33
5.5.5 Projects Identified ..................................................................................... 5- 33
5.6 Hydroelectric...................................................................................................... 5- 38
5.6.1 General Methodology ............................................................................... 5- 38
5.6.2 Major Assumptions................................................................................... 5- 38
5.6.3 Future Cost and Performance Projections................................................. 5- 39
5.6.4 Data Sources ............................................................................................. 5- 39
5.6.5 Projects Identified ..................................................................................... 5- 39
5.7 Wind Power ....................................................................................................... 5- 51
5.7.1 General Methodology ............................................................................... 5- 51
5.7.2 Major Assumptions................................................................................... 5- 52
5.7.3 Turbine Selection ...................................................................................... 5- 53
5.7.4 Future Cost and Performance Projections................................................. 5- 55
5.7.5 Data Sources ............................................................................................. 5- 55
5.7.6 Projects Identified ..................................................................................... 5- 55
5.8 Geothermal......................................................................................................... 5- 65
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5.8.1 General Methodology ............................................................................... 5- 65
5.8.2 Major Assumptions................................................................................... 5- 65
5.8.3 Future Cost and Performance Projections................................................. 5- 65
5.8.4 Data Sources ............................................................................................. 5- 66
5.8.5 Projects Identified ..................................................................................... 5- 67
6.0 Renewable Energy Financial Incentives.................................................................... 6- 1
6.1 Tax Related Incentives......................................................................................... 6- 1
6.2 Non Tax- Related Incentives ................................................................................ 6- 3
7.0 Renewable Energy Development Model Results ...................................................... 7- 1
7.1 Methodology........................................................................................................ 7- 1
7.1.1 Technology Characterization and Selection ............................................... 7- 2
7.1.2 Project Characterization.............................................................................. 7- 2
7.1.3 Future Cost and Performance Projections................................................... 7- 3
7.1.4 Transmission System Cost Analysis........................................................... 7- 3
7.1.5 Levelized Cost of Electricity Calculations ................................................. 7- 4
7.1.6 Supply Curve Development........................................................................ 7- 4
7.1.7 Model Limitations....................................................................................... 7- 6
7.2 Assumptions......................................................................................................... 7- 8
7.2.1 General Assumptions .................................................................................. 7- 8
7.2.2 Economic Assumptions ............................................................................ 7- 10
7.2.3 Arizona Renewable Energy Demand Assumptions.................................. 7- 12
7.3 Results................................................................................................................ 7- 13
8.0 Assessment of Key Risk Factors................................................................................ 8- 1
8.1 Sensitivity to Tax Credit Changes ....................................................................... 8- 1
8.2 Advanced Solar Technologies ............................................................................. 8- 1
8.3 Delayed Technical Advances............................................................................... 8- 2
8.4 Escalating Construction Costs ............................................................................. 8- 3
8.5 Manufacturing and Supply Chain Constraints..................................................... 8- 3
8.6 Near- Term Performance Learning Curve ............................................................ 8- 4
8.7 Competition for Limited Resources..................................................................... 8- 6
Appendix A. Consolidated Project Assumptions
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Appendix B. Forecast Cost of Energy for Each Project
Appendix C. Supply Curves
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List of Tables
Table 1- 1. Arizona Renewable Energy Resources Available in the Near- to Mid- Term. 1- 2
Table 3- 1. Renewable Energy Conversion Technologies............................................... 3- 1
Table 3- 2. Renewable Energy Projects in Arizona....................................................... 3- 11
Table 3- 3. Arizona Renewable Energy Standard Requirements. ................................. 3- 12
Table 4- 1. Biomass Levelized Cost of Energy Calculation............................................ 4- 4
Table 4- 2. Direct- Fired Biomass Combustion Technology Characteristics. .................. 4- 8
Table 4- 3. Biomass IGCC Technology Characteristics................................................ 4- 12
Table 4- 4. Cofired Biomass Technology Characteristics. ............................................ 4- 15
Table 4- 5. Arizona Utility Coal Fired Power Plants..................................................... 4- 16
Table 4- 6. Installed MSW Plasma Arc Gasification Projects....................................... 4- 18
Table 4- 7. Estimated Biomass Resources in Arizona ( Dry Tons/ Year). ...................... 4- 22
Table 4- 8. Farm- Scale Anaerobic Digestion Technology Characteristics.................... 4- 26
Table 4- 9. Arizona Biogas Potential ( MW) from Dairy and Swine Farms. ................. 4- 27
Table 4- 10. Landfill Gas Technology Characteristics .................................................. 4- 30
Table 4- 11. Candidate Landfill Gas Project Locations in Arizona............................... 4- 31
Table 4- 12. Solar Thermal Technology Characteristics. .............................................. 4- 39
Table 4- 13. 2005 World Cell Production by Technology Type ( MW). ....................... 4- 41
Table 4- 14. Solar PV Characteristics............................................................................ 4- 46
Table 4- 15. Theoretical Solar Power Production in Arizona........................................ 4- 48
Table 4- 16. Hydroelectric Technology Characteristics. ............................................... 4- 51
Table 4- 17. Further Development Unlikely ( environmental concerns)........................ 4- 53
Table 4- 18. Some Likelihood ( little or no environmental concerns)............................ 4- 53
Table 4- 19. US DOE Classes of Wind Power. ............................................................. 4- 56
Table 4- 20. Wind Technology Characteristics. ............................................................ 4- 57
Table 4- 21. Arizona Wind Technical Potential ............................................................ 4- 60
Table 4- 22. Geothermal Technology Characteristics. .................................................. 4- 63
Table 4- 23. Current Geothermal Development Prospects. ........................................... 4- 64
Table 4- 24. Fuel Cell Technology Characteristics. ...................................................... 4- 66
Table 4- 25. Renewable Technologies Performance and Cost Summary. a ................... 4- 70
Table 4- 26. Promising Technologies for Arizona......................................................... 4- 72
Table 5- 1. Significant Primary Mill Residue Suppliers.................................................. 5- 3
Table 5- 2. Estimated Average Annual Forest Thinning Residues ( 2006- 2015)............. 5- 3
Table 5- 3. Potential Forest Thinnings............................................................................. 5- 5
Table 5- 4. Biomass Resources Available for Cofiring. .................................................. 5- 6
Table 5- 5. Direct Fired and Cofired Biomass Project Characteristics............................ 5- 9
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Table 5- 6. Candidate Landfill Contact Results............................................................. 5- 11
Table 5- 7. Landfill Gas Project Characteristics............................................................ 5- 15
Table 5- 8. Per Head System Capacity for Anaerobic Digestion Processes.................. 5- 17
Table 5- 9. Anaerobic Digestion Project Characteristics............................................... 5- 20
Table 5- 10. Solar Thermal Electric Project Characteristics ( Constant 2007$)............. 5- 25
Table 5- 11. Solar Thermal Electric Project Characteristics.......................................... 5- 29
Table 5- 12. Solar Photovoltaic Project Characteristics. ............................................... 5- 36
Table 5- 13. Potential Hydroelectric Projects for Arizona. ........................................... 5- 40
Table 5- 14. Hydroelectric Project Characteristics. ....................................................... 5- 45
Table 5- 15. Potential Pumped Storage Development in Arizona. ................................ 5- 47
Table 5- 16. Cost Assumptions...................................................................................... 5- 53
Table 5- 17. Wind Class Comparison Assumptions by Wind Class ............................. 5- 53
Table 5- 18. Net Capacity Factors Per Wind Turbine Type. ......................................... 5- 54
Table 5- 19. Wind Power Project Characteristics.......................................................... 5- 64
Table 5- 20. Geothermal Project Characteristics. .......................................................... 5- 68
Table 6- 1. Major Production Tax Credit Provisions....................................................... 6- 2
Table 7- 1. Transmission Assumptions............................................................................ 7- 9
Table 7- 2. Future Modifiers ( Costs decrease in real terms).......................................... 7- 10
Table 7- 3. Economic Assumptions. .............................................................................. 7- 11
Table 7- 4. Arizona Renewable Energy Demand Forecast ( Cumulative GWh)............ 7- 13
List of Figures
Figure 1- 1. Total Arizona Renewable Supply Potential in 2025. ................................... 1- 8
Figure 3- 1. U. S. Electricity Generation by Source, 2005 ( Source: EIA)........................ 3- 2
Figure 3- 2. Cumulative Renewable Generation Capacity, MW ( Data from GED)........ 3- 4
Figure 3- 3. U. S. Annual Capacity Additions, MW ( Data from GED). .......................... 3- 5
Figure 3- 4. State Renewable Portfolio Standards ( as of May 2007). ............................. 3- 6
Figure 3- 5. Production Tax Credit Cycle and Impact on Wind Installations ( Data from
Figure 3- 6. Electricity Generation in Arizona by Source, 2005 ( Source: EIA).............. 3- 9
Figure 3- 7. Electricity Generation in Arizona 1990- 2005 ( Source: EIA). ..................... 3- 9
Figure 4- 1. 35 MW Biomass Combustion Plant............................................................. 4- 5
Figure 4- 2. General Gasification Flow. ........................................................................ 4- 10
Figure 4- 3. Coal and Wood Mix. .................................................................................. 4- 13
Figure 4- 4. Plasma Arc Torch Operating ( Source:
http:// www. zeusgroup. org/ applications. html).............................................. 4- 17
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Figure 4- 5. Large Wood Yard in Arizona ( Source: SFP). ............................................ 4- 21
Figure 4- 6. Arizona Urban Wood Waste Resource. ..................................................... 4- 23
Figure 4- 7. 135 kW Dairy Manure Digester................................................................. 4- 26
Figure 4- 8. Reciprocating Engine Used to Generate Power from LFG........................ 4- 28
Figure 4- 9. Kramer Junction Trough Plant ( NREL)..................................................... 4- 33
Figure 4- 10. Parabolic Dish Stirling System ( NREL). ................................................. 4- 35
Figure 4- 11. 10 MW Solar Two Power Tower System ( NREL). ................................. 4- 36
Figure 4- 12. Liddell Phase 1 CLFR Demonstration System. ....................................... 4- 38
Figure 4- 13. Worldwide PV Installations, MW ( Source: Renewable Energy World). 4- 41
Figure 4- 14. US Annual PV Installations ( Renewable Energy World). ....................... 4- 42
Figure 4- 15. Amonix: Flat Acrylic Lens Concentrator with Silicon Cells ( NREL).... 4- 43
Figure 4- 16. Solar Systems Pty, Ltd: Parabolic Dish PV Concentrator ( NREL). ....... 4- 44
Figure 4- 17. Solar Insolation Resource for a Flat- Plate Collector ( Source NREL). .... 4- 45
Figure 4- 18. US Module Costs, $/ Watt ( Source: Solarbuzz)........................................ 4- 45
Figure 4- 19. Arizona Concentrating Solar Power ( DNI) Resources ( NREL). ............. 4- 47
Figure 4- 20. 3 MW Hydroelectric Plant. ...................................................................... 4- 49
Figure 4- 21. Potential Hydroelectric Locations in Arizona.......................................... 4- 54
Figure 4- 22. Wind Farm near Palm Springs, California............................................... 4- 56
Figure 4- 23. Wind Resources in Arizona, Class 3 and Above. .................................... 4- 59
Figure 4- 24. COSO Junction Navy II Geothermal Plant. ............................................. 4- 62
Figure 4- 25. 200 kW Fuel Cell ( Source: UTC Fuel Cells). .......................................... 4- 65
Figure 5- 1. Levelized Cost Supply Curve for Solid Biomass Projects......................... 5- 10
Figure 5- 2. Levelized Cost Supply Curve for Biogas Projects..................................... 5- 16
Figure 5- 3. Levelized Cost Supply Curve for Solar Thermal Electric ( Trough) Projects. 5- 27
Figure 5- 4. Relative Capital Cost for Forecasts for Different Solar Technologies. ..... 5- 31
Figure 5- 5. Levelized Cost Supply Curve for PV Projects........................................... 5- 35
Figure 5- 6. Potential Hydroelectric Locations in Arizona............................................ 5- 43
Figure 5- 7. Levelized Cost Supply Curve for Hydroelectric Projects. ......................... 5- 44
Figure 5- 8. Potential Pumped Storage Locations in Arizona. ...................................... 5- 50
Figure 5- 9. Arizona Wind Energy Project Site Areas ( Wind Map: AWS Truewind). . 5- 57
Figure 5- 10. Buckhorn Project Area............................................................................. 5- 58
Figure 5- 11. Buffalo Range Project Site....................................................................... 5- 59
Figure 5- 12. Chevelon Project Area. ............................................................................ 5- 60
Figure 5- 13. Greens Peak Project Area......................................................................... 5- 61
Figure 5- 14. Kingstone Project Area. ........................................................................... 5- 62
Figure 5- 15. Levelized Cost Supply Curve for Wind Power Projects.......................... 5- 63
Figure 5- 16. Levelized Cost Supply Curve for Geothermal Projects. .......................... 5- 69
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Figure 7- 1. Renewable Resource Assessment Methodology.......................................... 7- 2
Figure 7- 2. Arizona Resource Supply Curve.................................................................. 7- 5
Figure 7- 3. 2015 Supply Curve..................................................................................... 7- 15
Figure 7- 4. Supply Curves. ........................................................................................... 7- 16
Figure 7- 5. Total Arizona Renewable Supply Potential in 2025. ................................. 7- 17
Figure 7- 6. Renewable Energy Mix.............................................................................. 7- 18
Figure 7- 7. Development Compared to Demand.......................................................... 7- 19
Figure 8- 1. Representative Solar Costs........................................................................... 8- 2
Figure 8- 2. Contract Failure Data for North American Renewables .............................. 8- 5
Figure 8- 3. Causes of Contract Failure, Frequency of Mentions.................................... 8- 5
Arizona Renewable Energy Assessment 1.0 Executive Summary
21 September 2007 1- 1 Black & Veatch
1.0 Executive Summary
Black & Veatch Corporation has prepared this report for Arizona Public Service
Company, Salt River Project, and Tucson Electric Power Company ( APS/ SRP/ TEP).
The purpose of this report is to assess the prospects for significant renewable energy
development in Arizona. The scope of the study is limited to Arizona projects that would
export power to the grid ( that is, not distributed energy projects). This study includes a
review of the current status of renewable energy in Arizona, characterization of
renewable power generation technologies, assessment of Arizona's renewable resources,
and an assessment of key risk factors. This section summarizes the key findings in these
1.1 Background and Objective
Electricity produced in Arizona is mostly from traditional natural gas, coal, and
nuclear resources. Hydroelectric contributes about 6 percent, while non- hydro renewable
resources are currently very small ( 0.07 percent). To stimulate further development of
renewable energy, the Arizona Corporation Commission adopted final rules in 2006 to
substantially increase Arizona's Renewable Energy Standard ( RES). The new RES
mandates that impacted utilities ( including TEP and APS) obtain 15 percent of their
energy from renewable resources by 2025. SRP has also adopted a renewable energy
goal similar to the RES.
The objective of this report is to assess the full potential of Arizona renewable
energy resources while accounting for the economics of developing those resources.
Large scale renewable energy development will be necessary to meet the renewable
mandates set forth in the Southwest. Although Arizona is well known for its solar
resources, solar is currently the most expensive renewable energy resource. By
comparison, Arizona is thought by many to have relatively limited opportunities for
comparatively lower cost renewables, such as wind, biomass, geothermal and
hydroelectric. This study assesses the relative potential of all resources and forecasts
which are most likely to be developed over the next 20 years. It is important to note that
this report concentrates on the potential of the renewable energy resources themselves.
It does not, beyond the inclusion of transmission interconnection costs, address the
potential cost or availability of transmission capacity needed to deliver these resources to
load. Further, out- of- state resources and their impact on the Arizona renewable energy
market are not included in the scope of this review.
This study was undertaken in two phases. The Interim Report ( Section 3, 4 and 6
of this Final Report) reviewed a broad range of renewable energy technologies and
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21 September 2007 1- 2 Black & Veatch
concluded with recommendations for further study in Phase 2. Phase 2 of the project ( the
remainder of this Final Report) characterizes the most promising options in greater detail
and identifies potential projects for possible implementation.
1.2 Renewable Energy Technology Options
Nineteen renewable and advanced energy technologies were assessed in Phase 1.
The technologies were split into eight categories as shown below. Each technology was
described with respect to its principles of operation, applications, resource characteristics,
cost and performance, environmental impacts, and outlook for Arizona applications.
Technologies that are bold and underlined in the list below were recommended
for further study in Phase 2 due to their large potential and/ or low cost.
1. Solid biomass
1.1 Direct fired
1.2 Biomass Gasification and IGCC
1.3 Cofiring
1.4 Plasma Arc Gasification
2. Biogas
2.1 Anaerobic digestion
2.2 Landfill gas
3. Solar Electric
3.1 Solar thermal electric
3.1.1 Parabolic Trough
3.1.2 Parabolic dish engine
3.1.3 Power Tower
3.1.4 Compact Lens Fresnel
3.2 Solar photovoltaic
3.2.1 Residential
3.2.2 Commercial
3.2.3 Utility- scale
4. Hydroelectric
4.1 Conventional Hydroelectric
4.2 Pumped Storage
5. Wind
6. Geothermal
7. Fuel Cells Using Renewable Fuels
8. Compressed Air Energy Storage
1.3 Renewable Resource Assessment
Additional research was performed for technologies that were recommended in
the first phase of the project. The objective was to assess the renewable energy resources
that are suitable for development in the near- to mid- term ( next 20 years). Potential
development prospects were identified, levelized generation costs were calculated, and
supply curves were developed for each resource. An end result of this process was the
identification of a list of over 100 hypothetical renewable energy projects that might be
developed to meet demands for renewable energy in Arizona ( Appendix A and B contain
lists of these projects). Table 1- 1 and Figure 1- 1 summarize the renewable energy
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21 September 2007 1- 2 Black & Veatch
resources in Arizona potentially developable over the near- to mid- term ( through 2025).
The table and figure do not include existing ( 24 MW) or planned projects ( 504 MW),
which are shown in Table 3- 2.
General findings from the resource assessment are described in the following
Table 1- 1. Arizona Renewable Energy Resources Available in the
Near- to Mid- Term.
Technology Location
( 2007$/
( GWh/ yr)
Direct Fired Biomass Maricopa 143 20 140
Biomass Cofiring 2 potential sites: TEP's
Sringerville generating station and
APS's Cholla generating station
58 - 63 20 140
Landfill Gas 15 potential small projects
identified across the state
82 - 99 10 68
Anaerobic Digestion Snowflake, Buckeye, Chandler,
and Maricopa
62 - 128 10 69
Solar Thermal Electric 100 MW project in 2011. 2– 4 200
MW sites per year after 2012
161- 176 4,300a 10,940a
Hydroelectric 7 potential sitesb 32 - 215 82 320
Wind 6 potential sites near Kingman and
the White Mountainsc
75 - 141 991 2551
Geothermal Clifton Hot Springs and Gillard
Hot Springs
110 - 122 35 215
Total 5468 14,443
a The solar potential is vast, and this only includes projects sufficient for meeting Arizona's forecast
renewable energy demands through 2025.
b Glen Canyon compromises 90 percent of total potential.
c 500 MW of planned wind generation not included.
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0 50 100 150 200
Biomass Cofiring
Landfill Gas
Anaerobic Digestion
Biomass Direct
Solar Thermal
Levelized Cost of Energy ($/ MWh)
Near- term
( GWh/ yr)
Other Hydroelectric Projects
Other Wind Kingstone
Figure 1- 1. Summary Cost and Potential of Arizona Renewable Resources.
1.3.1 Direct Fired and Cofired Biomass
Although biomass resources are limited, direct- fired biomass and cofired biomass
technologies were identified as promising technologies in the first stage of the analysis.
Sufficient resource was identified in central Arizona to support a 20 MW direct- fired
combustion plant in the vicinity of Maricopa. This facility would be a low emission,
fuel- flexible fluidized bed that would burn a variety of biomass fuels, including mill
residues, urban wood waste from Phoenix and Tucson, and agricultural residues. The
two potential cofiring projects are a 10 MW facility located at TEP's Springerville
Generating Station and a 10 MW facility located at APS's Cholla Generating Station. To
counter potential negative impacts on the boilers, the cofiring projects were assumed to
use a gasification system close- coupled to the existing boiler. The cofiring projects
would utilize forest and mill residues.
Considering the other renewable energy options evaluated in this study, the costs
of the two cofiring projects are relatively low ( about $ 60/ MWh in 2010), and the costs of
cofiring are certainly lower than the direct fired project ( about $ 162/ MWh in 2012). In
general, the costs of biomass in Arizona are high compared to other states due to limited
available low cost biomass and the small scale of the potential projects.
While cofiring is lower cost than direct fired biomass plants, there are a couple of
significant barriers to its implementation. Initiating a biomass cofiring project may
require the host coal plant to reopen existing air permits, even though cofiring generally
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reduces emissions. The risk and cost of reopening existing permits is not included in the
cofiring cost estimate, but it may be a significant deterrent to cofiring projects. Further,
electricity demand in Arizona is increasing faster than any other state ( 600 MW increase
per year). Biomass cofiring converts capacity to a renewable source rather than adds
capacity, and thus may be less attractive than new capacity additions.
If the cofiring projects face too many obstacles, an additional direct fired biomass
facility could be developed in Northern Arizona in lieu of the cofiring projects.
1.3.2 Landfill Gas
Black & Veatch utilized the Environmental Protection Agency Landfill Methane
Outreach Program ( LMOP) database of landfills in Arizona to assess 25 potential sites.
Black & Veatch attempted to contact each of the landfills to verify data and assess the
suitability for power development. Based on this review, fifteen potential projects were
identified, totaling 9.7 MW of capacity and 68 GWh of annual generation. This capacity
is much smaller than what would be expected for similar sized landfills in other states
due to Arizona's dry climate. Most of these projects could be available by 2010 if
development were prioritized. Projects costs vary, but most projects are projected to
generate power for around $ 90/ MWh.
The overall prospects for landfill gas generation are small. Landfill gas projects
can take less time to develop than large solar or wind projects, so landfill gas may play a
more significant role in the near term.
1.3.3 Anaerobic Digestion
The utilization of biogas generated from anaerobic digestion of animal manure
was identified as a technically feasible option in the first stage of the analysis. Potential
anaerobic digestion projects were identified based on large concentrations of livestock
( swine, dairy, and poultry) operations within an area. Four anaerobic digestion projects
were identified, ranging from 1.5 to 3.5 MW. The projects total 9.9 MW of capacity and
69 GWh of annual generation. The costs for the anaerobic digestion projects range from
$ 70/ MWh to $ 140/ MWh ( in 2010), largely dependent on project scale.
While this resource has a relatively limited generation potential, anaerobic
digestion projects could be executed relatively quickly and with low levels of risk.
1.3.4 Solar Thermal Electric
There is large potential for solar thermal development in Arizona. The review
focused on the only commercially proven technology: parabolic trough. Parabolic dish
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21 September 2007 1- 5 Black & Veatch
Stirling systems are promising, but unproven; their costs were assessed in a side scenario
study ( section 8).
The potential for solar thermal was characterized in a different manner than other
technologies. Rather than being limited by resource availability, the technology is
limited by equipment availability, development timelines, and ultimately economics.
Due to supplier constraints, it was assumed that the first 100 MW trough plant in Arizona
would not be completed until 2011. It is assumed that the near term supply chain
constraints in the industry will be alleviated by 2013, and two to four 200 MW plants
could be constructed per year thereafter. Generic projects were characterized in four areas
of the state: Phoenix, Yuma, Stoval, and Tucson.
Unlike most other technologies evaluated for this study, it is expected that
significant technical and cost advances will be realized for solar thermal trough plants. In
addition, parabolic dish engine technology may also be deployed on a commercial level,
and this technology could become competitive over the term of this study ( through 2025).
The supply curve for solar thermal trough plants is relatively flat with the lowest
cost projects generating power for about $ 160/ MWh ( hypothetical 2007 project, includes
30 percent investment tax credit). The flat supply curve means that a lot of solar thermal
can be developed for about the same cost. This cost is substantially higher than non- solar
resources profiled in this study. The potential supply of solar thermal potential is vast,
and exceeds the near- term demands for renewable energy in Arizona.
1.3.5 Solar Photovoltaic
As with solar thermal technologies, constraints on the deployment of solar
photovoltaic projects are not related to resource; the constraints are mainly capital costs
and equipment availability. The review focused on deployment of larger photovoltaic
systems ( 5- 10 MW). Concentrating photovoltaic technology was also addressed as a
possible future technology.
Even with significant cost reductions, costs for solar photovoltaic and
concentrating photovoltaic projects are too high ( greater than $ 240/ MWh) to compete
with the other renewable energy technologies surveyed. However, an advantage of solar
photovoltaics is that smaller projects may be able to come online in the very near- term
( 2008 and 2009). As such, they are one of the few in- state technologies available to meet
near- term renewable energy demand.
Alternative project and cost structures for solar PV projects are currently being
refined, and they have the potential to substantially lower the " all- in" cost of energy from
solar PV. Given the high capital costs for PV, any improvement in capital structure or
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financing costs has a relatively strong impact on the final levelized cost. These structures
have not been modeled in this report.
1.3.6 Hydroelectric
Seven hydroelectric projects were identified as potentially promising. The total
combined capacity of the seven projects identified is 81.8 MW, with an energy
generation potential of 320 GWh/ yr. A single project, adding generation at Glen Canyon
dam, makes up about 90 percent of this total. The projects were identified based on
government information, and details were difficult to verify. Of the seven projects, Glen
Canyon, Tucson and Waddell are the only projects that could be reasonably located.
Glen Canyon and Waddell have the most head and flow available compared to other
sites. They also have existing hydropower installed and therefore show the most potential
for further study. The Glen Canyon project is the lowest cost project of all the renewable
energy projects surveyed for this study. It is forecast to cost about $ 50/ MWh in 2015, the
year it is projected to be available. The other hydroelectric projects are all projected to be
much more expensive, at costs over $ 150/ MWh in 2013, the first year they are projected
to be available.
Drought conditions of recent years have reduced water resources throughout the
Western US in recent years, including Lake Powell. Continued drought conditions may
decrease the actual statewide hydroelectric potential.
1.3.7 Wind Power
While the wind resource is generally less attractive in Arizona compared to
surrounding states, wind was identified as one of the more promising resources in the
first phase of the study. To identify specific areas conducive to the development of a
utility- scale wind energy projects, information was gathered on Arizona's estimated wind
resource, transmission infrastructure, environmental restrictions, and federal land areas.
After reviewing many potential sites for constructability, transmission proximity, wind
resource, and other constraints, six sites were chosen as the most promising for near- term
development. While it is possible that other wind sites could be developed in Arizona,
these sites are less attractive based on this analysis.
The total combined capacity of the six sites identified is 990 MW, with an energy
generation potential of 2,550 GWh/ yr. ( The 500 MW of already planned wind projects
are not included in this total). Costs for most projects are estimated to be about $ 75 to
$ 100/ MWh in 2010, which is the year when wind is first expected to be available. While
the wind resources in Arizona are modest when judged against many other states,
compared to other renewable energy options in Arizona, prospects for wind are good due
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to the relatively low cost. Arizona wind resources, however, are stronger in the winter
when electricity demand is low, and weaker in the summer when demand is higher.
Assessment of the seasonal value of energy ( or avoided cost, more generally) was not
included in the scope of this study.
1.3.8 Geothermal
Geothermal was identified as a relatively unknown, but potentially promising
resource in the first phase of this study. The two known geothermal resources with the
highest temperatures are located in the eastern part of the state: the Clifton Hot Springs
and the Gillard Hot Springs projects. Interpretation of preliminary data suggests that
resource temperatures may enable binary power generation.
Because the projects are still in their early exploratory state, there is not enough
data available to accurately characterize the geothermal projects with a high degree of
precision. Even identifying the potential project size is still speculative. For this reason,
generic 20 and 15 MW projects were assumed. At best, these assumptions identify
" place- holder" projects that must be further defined as more information about the true
potential of each site is discovered. Because of their small- scale and long lead time
( which places them after the assumed expiration of the production tax credit), costs for
the two projects are relatively high ($ 149/ MWh and $ 163/ MWh in 2014). Nevertheless,
this cost is still competitive with solar resources that are expected to be developed in the
same timeframe.
1.4 Forecasted Renewable Energy Development
Black & Veatch has developed a model to help utilities, states, and other entities
develop renewable energy plans. For the utilities represented in this study, Black &
Veatch evaluated Arizona's renewable energy development potential in light of increased
demand for renewable energy stimulated, in part, by the Renewable Energy Standard.
The model was then used to forecast renewable energy development in the state through
The model evaluates the total lifecycle cost of renewable energy projects,
including capital and operating costs, performance, and transmission system
interconnection. Projections are made for future changes in technology cost and
performance based on Black & Veatch's experience. By allowing the model to consider
all possible renewable energy resources in Arizona, the study assesses the full potential of
all renewable energy resources while accounting for the economics of developing those
resources. The model does not include transmission system upgrades ( other than
interconnection costs) or system integration costs for intermittent resources ( e. g. wind).
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The model also does not assess value ( i. e., avoided cost) of the resource as determined by
its degree of firmness or time of delivery ( e. g. on- peak vs. off- peak). In selecting
projects, utilities may consider these factors, which may result in a different order of
resource/ project development. Further, although long term transmission constraints have
not been reviewed, a long term analysis should include a transmission development plan.
Figure 1- 2 shows the total renewable energy supply curve for Arizona in the year
2025. Costs are in nominal dollars ( that is, 2025 costs) without tax credits. This curve
shows all new projects identified in the study. The curve also shows a demand line
indicating the projected 2025 renewable energy demand of 11,210 GWh ( this already
accounts for planned projects). If development of renewables in Arizona were
economically optimum ( again, not considering transmission upgrades and avoided costs),
then all of the projects to the left side of the demand line would be built by 2025. It
should be noted that there are additional higher cost resources that would extend the
potential supply of renewables further to the right than indicated on this chart. However,
once sufficient projects were identified to meet demand, Black & Veatch did not continue
to identify higher cost projects.
0 5,000 10,000 15,000 20,000 25,000
2025 Demand: 11210
Generation, GWh
Levelized Cost, $/ MWh
2025 Supply Curve
Figure 1- 2. Total Arizona Renewable Supply Potential in 2025.
The supply curve shows that a portion of Arizona's renewable energy demands
can be met with lower cost non- solar resources, especially wind. However, by 2017, it is
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projected that lower cost non- solar resources will be exhausted and large- scale solar
thermal plants will then be built at a rate of 200 to 400 MW per year through 2025. Other
insights from the model include:
• Non- solar resources limited – Arizona has a variety of renewable energy
resources that could be developed; however, other than solar, these resources
appear relatively limited. In the mid to near- term, developable potential for
new biomass, geothermal, and hydroelectric projects combined could
contribute about 952 GWh/ yr, or 1 percent of the electricity that was
generated in Arizona in 2005. Wind could contribute about 2.5 percent. With
energy storage, solar could theoretically supply the entire electricity needs of
the state. ( Note that these totals exclude 825 GWh/ yr of additional existing
and already planned projects, most of which is wind).
• Non- solar resources important – Despite the relatively limited potential of
wind, biomass, geothermal and hydroelectric resources, they serve an
important role in forestalling the need to install expensive solar. However, the
relatively limited potential of these resources compared to surrounding states
may serve as a deterrent for large, out- of- state renewable energy project
• Regional renewable energy markets – This study did not include an
assessment of regional renewable energy supply and demand. Neighboring
states, namely California, New Mexico, and Nevada, also have aggressive
renewable energy standards. These states may have more economical
renewable energy sources than Arizona ( for example, Salton Sea geothermal
resources and New Mexico wind); however, given their own aggressive in-state
demands and transmission limitations, they may not be a dependable
source for Arizona. While the importation of renewable energy may help to
defer Arizona's needs, it is not likely to fully satisfy them.
• Lowest cost resources – The most promising project opportunities from an
economic perspective involve enhancements to existing facilities: adding a
unit at the existing Glen Canyon hydroelectric project and biomass cofiring at
the Cholla and Springerville coal plants. These projects are around $ 60/ MWh
or less.
• Solar about twice cost of other resources – Solar is the most expensive of
the renewable resources profiled in this study. The lower cost solar resources
( about $ 161- 176/ MWh in 2007) are about twice as expensive as the bulk of
the non- solar resources ( about $ 70- 110/ MWh in 2007). The base case model
included only proven, fully commercial solar technologies such as solar
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photovoltaics and solar thermal trough. If forecasted technology
improvements are realized, dish engine technologies have the potential to be
cost competitive with conventional parabolic trough systems.
• Arizona's reliance on solar is unique – Arizona appears unique in the U. S.
in its dependence on in- state solar energy to meet its renewable energy
demands. It is estimated that 65 percent of the Arizona renewable demand in
2025 will be met by solar. Generally speaking, other states in the Southwest
U. S. will likely be less reliant on solar to meet their renewable energy
requirements. This is because other states generally have a larger base of non-solar
renewables that they can rely on for near- term needs. By comparison,
Arizona's non- solar resources are relatively limited. Solar technologies will
play a key part of renewable's future in Arizona.
• Consideration of avoided costs is important and necessary – This project
did not assess the differential value ( i. e., avoided cost) of renewable resources.
Avoided cost is typically determined by assessing a resource's capacity value
( based on degree of " firmness" at the time of a utility's system peak demand)
and its energy value ( based on time of delivery). In selecting projects to
develop or procure, utilities may consider these factors, which may result in a
different order of resource/ project development than shown in the supply
curves in this report. This is important when comparing resources such as
wind and solar. For example, wind energy projects only provide fractional
capacity value ( often estimated at 20 percent of the nameplate capacity) and
are more likely to offset low cost energy resources during the winter and
spring. Solar resources can readily provide firm capacity with gas
hybridization or thermal storage. Further, solar is generally coincident with
times of higher capacity needs. There are numerous methods to calculate
avoided cost, and costs are specific to individual utility systems.
1.5 Assessment of Key Risk Factors
Black & Veatch analyzed some of the risk factors of interest to utilities in Arizona
to determine how sensitive the supply curve results would be to changing situations.
These factors include tax credit changes, implementation of advanced solar technologies,
delayed technical advances, escalating construction costs, manufacturing/ supply chain
constraints, near term performance learning curve, and competition for limited resources.
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1.5.1 Tax Credit Changes
Most renewable resources benefit from either production tax credits ( PTCs) or
investment tax credits ( ITCs). The base case model assumed tax credits expire in 2012.
In the long term, whether tax credits expire in 2008 or 2012 has little impact on the
cumulative average cost of meeting renewable energy demand in Arizona ( less than 1
percent by 2025). This is because many of the most expensive, large solar projects would
likely be built after 2012. If tax credits never expire, the impact is a significant reduction
in cumulative portfolio costs ( 25 percent reduction).
1.5.2 Advanced Solar Technologies
There are pre- commercial advanced solar technologies that may reduce the cost of
solar energy. Two of these technologies include concentrating solar photovoltaic ( CPV)
and parabolic dish engine. These technologies were not included in the base case model,
but were modeled in a sensitivity analysis. Based on Black & Veatch's assumptions,
technology advancements in CPV will not make that technology competitive with
conventional solar parabolic trough technologies for utility scale applications. However,
there does appear to be potential for dish engine technologies to become competitive with
solar trough technology.
1.5.3 Delayed Technical Advances
Advances are expected in wind and solar technologies, resulting in lower costs
and higher capacity factors. However, there is a risk that such advancement may be
delayed or not realized, and this was investigated in a sensitivity analysis. When
technology advances were delayed, wind and solar thermal projects had lower capacity
factors compared to the base case, which required development of more projects to meet
the same demand. Because of lack of advancement, solar projects, particularly in the
later years, are higher cost than the base case. The reduced technical advances will make
levelized costs for wind and solar higher, which will make other technologies ( biomass
and geothermal) comparatively more attractive in early years. The cumulative effect on
the total renewable energy cost will likely be an increase of 15 to 20 percent by 2025.
1.5.4 Escalating Construction Costs
The model base case has a capital cost escalation of 2.5 percent per year, which is
meant to track close to general inflation. There is a risk that construction costs will
escalate at a higher rate, depending on future markets for materials and labor. A
sensitivity analysis was performed assuming 5 percent escalation. The results are
pronounced. At year 2025, levelized costs are about 37 percent higher than the base case.
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1.5.5 Manufacturing and Supply Chain Constraints
Manufacturing and supply chain constraints were assumed in the model. The
projects most likely to be impacted by such constraints are solar and wind. For wind
projects, there is currently a delay of up to two years between turbine order and turbine
delivery because demand is greater than manufacturing capability. The wind projects
identified for this project are assumed to be available to come online between 2010 and
2013. If there are additional constraints in the turbine supply chain, then it is likely that
renewable energy demand would not be met in some years with in- state resources.
Solar projects were also modeled with manufacturing constraints in mind. Due to
these constraints, it has been assumed that the first 100 MW trough plant in Arizona
could not be completed until 2011. It is assumed that the near- term supply chain
constraints in the industry will be alleviated by 2013, and two to four 200 MW plants
could be constructed per year thereafter if deemed economical
1.5.6 Near- Term Performance Learning Curve / Project Failure
In the near- term, projects may under- deliver renewable energy as they gain
experience during the initial operational and development learning period. Projects may
also fail outright, and not supply any renewable energy. From a supply curve standpoint,
contract failure shifts the supply curve to the left. When a project fails, its generation is
removed from the supply curve, while all projects to the right ( more expensive projects)
shift left to fill in the space. As lower- priced projects fail, utilities will be forced to
contract with more expensive renewable projects to procure the necessary amount of
1.5.7 Competition for Limited Renewable Resources
As more and more renewable energy projects are developed, there will be fewer
renewable resources to utilize in the future. There is a risk that utility competition for
limited renewable resources will increase prices. This is particularly true in supply-constrained
markets. For Arizona utilities, it is possible that renewable energy
developers may set energy prices as high as possible while still beating the marginal cost
of competing energy supplies. This would increase the total renewable energy cost, but it
is uncertain to what extent.
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2.0 Introduction
Black & Veatch Corporation has prepared this study of renewable energy for the
three largest utilities in Arizona: Arizona Public Service Company, Salt River Project,
and Tucson Electric Power Company ( APS/ SRP/ TEP). The purpose of this report is to
assess the prospects for significant renewable energy development in Arizona. The scope
of the study is limited to Arizona projects that would export power to the grid ( that is, not
distributed generation projects).
This study includes a review of the current status of renewable energy in Arizona,
characterization of renewable power generation technologies, assessment of Arizona's
renewable resources, and an assessment of key risk factors.
2.1 Background
In response to increasing public interest in clean energy sources, concerns about
energy security, and the environmental impacts of fossil fuels, numerous states have
encouraged development of renewable energy sources. Renewable energy standards
have been a popular mechanism used by other states and countries to mandate a certain
percentage of electricity be generated from renewable energy resources.
Electricity in Arizona is largely produced from traditional natural gas, coal, and
nuclear resources. Hydroelectric contributes about 6 percent, while non- hydro renewable
resources are currently very small ( 0.07 percent). To stimulate development of
renewables, Arizona was one of the earlier states to adopt a renewable energy standard.
Arizona enacted its original Environmental Portfolio Standard ( EPS) in March of 2001.
The EPS required that investor owned utilities provide 1.1 percent of their power from
renewables by 2007.
In November 2006, the Arizona Corporation Commission adopted final rules to
substantially increase Arizona's Renewable Energy Standard ( RES) such that some
utilities would be required to obtain 15 percent of their energy from renewable resources
by 2025. Such a standard places Arizona among the most aggressive in the nation. In
addition, Arizona is surrounded by other states in the Southwest ( California, Nevada, and
New Mexico) that also have strong renewable energy standards. The combined effect of
these standards is to substantially increase the demand for renewable energy in the
2.2 Objective
The objective of this report is to assess the full potential of all Arizona renewable
energy resources while accounting for the economic variables of developing those
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resources. Large scale renewable energy development will be necessary to meet the
renewable mandates set forth in the Southwest. Although Arizona is well known for its
solar resources, solar is the most expensive renewable energy resource. By comparison,
Arizona is thought by many to have relatively limited opportunities for lower cost
renewables, including wind, biomass, geothermal and hydroelectric. This study assesses
the relative potential of all resources and forecasts which are most likely to be developed
over the next 20 years.
2.3 Approach
Black & Veatch has developed an objective methodology to assess renewable
energy potential based on sound utility generation planning fundamentals and the specific
challenges inherent to analyzing renewable energy generation technologies. This study
was undertaken in two phases. This final report is a comprehensive account of both. An
Interim Report covered Phase 1. It described the current status of renewable energy in
Arizona, characterized renewable power generation technologies and the general
potential of the different resources, and reviewed available financial incentives for
renewable energy. The Interim Report ( Section 3, 4 and 6 of this Final Report) reviewed
a broad range of renewable energy technologies and concluded with recommendations
for further study in Phase 2. Phase 2 of the project ( the remainder of this Final Report)
characterizes the most promising options in greater detail and identifies potential projects
for possible implementation.
This study began with an assessment of renewable energy generation technologies
to identify the most promising technologies for Arizona. The following technologies
were initially identified as potentially promising:
• Wind
• Solar Thermal ( trough)
• Solar Thermal ( dish)
• Solar Photovoltaics
• Direct Biomass Combustion
• Cofired Biomass
• Anaerobic Digestion
• Landfill Gas
• Hydroelectric
• Geothermal
Following identification of the most promising technologies, a resource
assessment was performed to quantify the near- term developable potential of the
promising renewable resources. In some cases, the assessment included new primary
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research and initial siting activities to collect renewable energy resource data. This
information was used to determine the size of the resources, geographic distribution, and
technical feasibility of utilization. An end result of this process was the identification of
a list of over 100 hypothetical renewable energy projects that might be developed to meet
demands for renewable energy.
Following the resource assessment, the total lifecycle costs were calculated for
each renewable energy project. Costs included capital and operating costs, performance,
transmission system interconnection, and financial incentives. Transmission costs, which
can be significant, have not been included at this stage of the analysis. Projections were
also made for future changes in technology cost and performance based on Black &
Veatch's experience in the field. Resource estimates were combined with technology
characteristics to develop a set of economic supply curves showing the renewable energy
available ( MWh) at different levelized costs ($/ MWh). The supply curves for the
individual renewable energy technologies were then combined to generate statewide
renewable energy supply curves. The supply curves can be used to identify a
hypothetical least- cost set of renewable energy projects through 2025.
Once the base model was established, it was used to test the model results against
various key risk factors.
2.4 Report Organization
Following this Introduction, this report is organized into the following sections:
• Section 3 – Renewable Energy Overview: This section provides an
overview of renewable energy including the historical development of
renewables in the US followed by the status of renewable energy in Arizona.
• Section 4 – Assessment of Renewable Energy Technology Options: This
section reviews the general characteristics and costs of renewable energy
technology options for Arizona. The section concludes with a short list of
technologies recommended for further study.
• Section 5 – Renewable Resource Assessment: This section summarizes the
renewable energy resources of Arizona that are suitable for development in
the near- to mid- term ( next 20 years). Potential development prospects are
identified, levelized generation costs are calculated, and a set of supply curves
is developed.
• Section 6 – Renewable Energy Financial Incentives: This section describes
the existing and proposed incentives that are available to new renewable
energy facilities.
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• Section 7 – Renewable Energy Development Model: This section
summarizes the supply curve model. The model is described, assumptions are
outlined, and key results are presented.
• Section 8 – Assessment of Key Risk Factors: Black & Veatch analyzed
some of the risk factors of interest to utilities in Arizona to determine how
sensitive the supply curve results would be to changing situations. These
factors include changes in tax law, delayed technical advances, escalating
construction costs, manufacturing/ supply chain constraints, near term
performance learning curve, and competition for limited resources.
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3.0 Renewable Energy Overview
This section provides an overview of renewable energy including the historical
development of renewables in the US followed by the status of renewable energy in
Renewable energy generation technologies are based on energy sources that are
practically inexhaustible in that most are solar derivatives. Such technologies are often
favored by the public over conventional fossil fuel technologies because of the perception
that renewable technologies are more environmentally benign. Renewable energy
options include wind, solar, biomass, biogas, geothermal, hydroelectric, and ocean
energy. Table 3- 1 shows the power conversion technologies that have been developed to
harness these energy sources.
Table 3- 1. Renewable Energy Conversion Technologies
Renewable Resource Energy Conversion Technology
Solar Photovoltaic
Thermal electric ( trough, dish, etc.)
Thermal water heating
Absorption chilling
Wind Wind Turbines
Water Hydroelectric Turbines
Pumped Hydro Storage ( also Compressed Air Storage)
Ocean Wave Energy Devices
Tidal/ Current Energy Turbines
Thermal Energy Conversion
Geothermal Steam Turbines
Direct Use
Geothermal Heat Pumps
Biomass Combustion ( direct fired, cofiring with coal)
Gasification / Pyrolysis
Biogas, Biodiesel, Ethanol Engine generators
Combustion turbines
Fuel cells
Renewable technologies have been developed to harvest energy from wind, solar
radiation, biomass, water, and the earth's thermal energy. Although the potential
resources are very large, non- hydro renewable energy currently only supplies about 2
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21 September 2007 3- 2 Black & Veatch
percent of the electricity demand in the United States. Figure 3- 1 is a summary of
electricity generation for the United States in 2005, including a breakdown of the
renewable energy portion of generation. The figure shows that renewable sources
represent only a few percent of total electricity generation. The largest sources of
renewable generation are hydroelectric followed by biomass, such as wood waste.
Although increasing in popularity, other renewable energy sources, including wind and
solar, make up much smaller portions of the total.
Hydro ( b)
Biomass ( c)
Natural Gas ( a)
a Includes a small amount of other gases ( propane, refinery gas, etc.)
b Includes pumped storage hydro
c Includes w ood, w aste- to- energy, landfill gas, agricultural byproducts, etc.
Figure 3- 1. U. S. Electricity Generation by Source, 2005 ( Source: EIA).
Recent natural disasters coupled with increased global demand and political
instability led to sharp increases in oil and natural gas prices. Energy supply and security
has become a topic of concern among policy makers and the public at large. In addition
to their price volatility, fossil fuels emit pollutants and are often imported from other
states or countries. Policy makers have historically looked to renewable energy to
address these issues, and interest is resurging again.
3.1 Historical Development of Renewable Energy
Modern forms of non- hydro renewable energy technology have largely developed
over the last thirty years. Industry growth has been uneven in response to abruptly
shifting market forces, changing government policies, and evolving technology.
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3.1.1 1978- 1991: PURPA and Standard Offer Contracts
The modern era of renewable energy arose from the initial oil shortages of the
1970s. In 1978, the federal government passed the Public Utilities Regulatory Policy
Act, which stimulated widespread development of renewable energy projects. Under
PURPA, many biomass, wind, and geothermal plants came online and were allowed to
sell excess power to the utility at an avoided cost or other negotiated rate. Some of these
costs/ rates, particularly in California, were tied to high forecasts of future fossil prices.
The generous PURPA contracts combined with other financial incentives allowed
California to lead the world in development of biomass, geothermal, wind and solar
technologies. Ultimately, PURPA spurred the development of the independent power
producer ( IPP) industry. IPPs currently dominate ownership of renewable energy plants.
As shown in Figure 3- 2 and Figure 3- 3, growth of the renewable energy industry
was faster during the 1980s than at any other time in recent history – with the possible
exception of the current renewables " boom." During this period the predominant
technologies implemented were biomass, waste to energy, and geothermal. In fact, up
until 1999, biomass and waste accounted for approximately two- thirds of renewable
generation capability installed in the US ( nameplate basis). However, wind energy
technology, which had matured in Europe, was to soon take over leadership.
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1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004
Cumulative Renewables -- Nameplate Capacity, MW
Municipal Waste
Figure 3- 2. Cumulative Renewable Generation Capacity, MW ( Data from GED1).
1 Black & Veatch analysis of data from Global Energy Decisions' proprietary " Energy Velocity" database,
May 2006.
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1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004
Annual Additions -- Nameplate Capacity, MW
Municipal Waste
Solar Geothermal
Figure 3- 3. U. S. Annual Capacity Additions, MW ( Data from GED).
3.1.2 1992- 2004: The PTC and RPS Era
As the influence of PURPA waned with lower electricity costs in the 1990s, a
new round of renewable energy development, mostly wind, was spurred by the
Production Tax Credit ( PTC) enacted in 1992. Despite the new incentive, development
in the early 1990s was at a much slower pace than during the 1980s.
Near the latter half of the last decade, states began to implement Renewable
Portfolio Standards ( RPS) mandating that a certain percentage of electricity supply come
from renewable sources. RPS programs accelerated the development of renewables ( see
Figure 3- 2). To date, 22 states have implemented RPS policies mandating that a portion
of power supplied to retail customers come from renewable energy sources. RPS goals
vary greatly by state, as does the specific consideration for biomass energy. Notable state
RPS programs include California ( 20 percent renewables by 2010), New York ( 24
percent by 2013), Massachusetts ( 4 percent by 2009), and Pennsylvania ( 18 percent by
2020). Figure 3- 4 shows the various state renewable portfolio standards.
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By 2009,
+ 1%/ yr
States with RPS Requirements
States with RPS Goals
by 2010
by 2015,
5% Solar
By 2025 NM: 20%
by 2020
by 2015
by 2025
( Xcel
by 2015
IL Goal:
By 2013
By 2020
By 2021
By 2010
By 2019
By 2020
by 2020
4% Solar
by 2013
Tier I/ II
by 2020
By 2022
VT Goal: All New
MT: 15% Gen, 10% cap
By 2015
By 2019
By 2020
NH: 16% new
Gen By 2025
VA Goal:
By 2022
Figure 3- 4. State Renewable Portfolio Standards ( as of May 2007).
Based on developments in Europe, wind energy technology had also greatly
improved from the designs of the 1980s. Wind benefited greatly from the combination of
preferential PTC treatment, RPS programs, and improved technology. Since 1999, about
90 percent of all new renewable energy development has been wind ( nameplate capacity
basis). Prior to 1999, wind comprised about 10 percent of total renewables additions.
3.1.3 2005: Energy Policy Act
In the past year, changes in federal tax policy and a surge in demand for
renewable energy have caused a new era in renewable energy development.
Federal involvement in the energy industry has traditionally been limited due to
strong state regulation; however, the federal government is increasing its role, especially
with respect to renewable energy. Recently, the government has significantly expanded
tax and other incentives for renewable energy developers through the Energy Policy Act
of 2005 ( EPAct). The federal government has traditionally funded renewable research
and development through the Department of Energy, and President Bush's recent state of
the Union address called for more investment and spending on renewables.
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The Energy Policy Act of 2005 included significant changes to renewable energy
incentives, particularly related to the tax code. The changes in the tax code from the
EPAct are significant: the PTC was extended to many new technologies and the
Investment Tax Credit ( ITC) was increased from 10 percent to 30 percent for solar.
The PTC provides a tax credit of 1.5 cents per kWh of eligible renewable
generation for the first ten years of the project's life. The full credit is adjusted for
inflation, and is worth $ 20/ MWh as of 2007. Some resources receive half the PTC
amount, currently $ 10/ MWh. The PTC has gone through an " up and down" cycle of
expiration and renewal over the past few years ( see Figure 3- 5). Originally enacted as
part of the Energy Policy Act of 1992, the credit has expired numerous times before
being renewed by Congress. The gaps in the PTC record have caused the wind market to
cycle through boom and bust periods of development. Prior to October 2004, the PTC
applied only to the production of electricity from wind and " closed- loop" biomass ( and
poultry waste for a brief period). Wind is the only technology that benefited significantly
from the PTC during this timeframe.
Additional information on the ITC, PTC, and other renewable energy incentives is
provided in Section 6 of this report.
1998 1999 2000 2001 2002 2003 2004 2005
Annual Wind Additions -- Nameplate Capacity, MW
6/ 99 - PTC Expires
Extended 12/ 99
12/ 01 - PTC Expires
Extended 2/ 02
12/ 03 - PTC Expires
Extended 10/ 04
8/ 05 - PTC Extended ( Before
Expiration) to 12/ 07
" Boom and Bust"
Production Tax Credit
Figure 3- 5. Production Tax Credit Cycle and Impact on Wind Installations ( Data
from GED).
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The PTC again expired at the end of 2003 and was not renewed until October 4,
2004,2 as part of the Working Families Tax Relief Act of 2004 ( H. R. 1308). This Act
extended the credit through December 31, 2005 and expanded it to include additional
resources. The timing of this extension did little to spur new development of non- wind
projects. The Energy Policy Act of 2005 modified the PTC and extended it through
December 31, 2007. Another one year extension ( Through December 31, 2008) was
recently granted through the Tax Relief and Health Care Act of 2006. Due to the
expanded timeframe and eligibility, the latest revisions have accelerated development of
many different types of renewable energy. The PTC is now available for all the major
renewable resources, with some receiving the " full" PTC and others the " half" credit ( see
Section 6 for details).
In the past, the PTC has been successful in encouraging development of wind
energy but not other technologies. Closed- loop biomass ( including poultry waste for a
short time) was the only other technology eligible prior to 2004. Biomass was not
developed due to restrictive definitions placed on fuel eligibility. However, the recent
expansions and extensions of the PTC are now stimulating widespread development of all
types of renewable energy technologies.
3.2 Renewable Energy Status in Arizona
Figure 3- 6 shows the electricity generation data for Arizona in 2005. Current
energy sources are comprised largely of traditional natural gas, coal, and nuclear
resources. Hydroelectric contributes about 6 percent, while non- hydro renewable
resources are currently very small ( 0.07 percent).
Figure 3- 7 shows the historical generation data for Arizona from 1990 to 2005.
Reviewing this information shows two key facts: ( 1) electricity generation in Arizona is
increasing rapidly ( over 60 percent growth from 1990 to 2005) and ( 2) the proportion of
natural gas in Arizona's electricity supply has increased rapidly, from about 3 percent in
1997, to over 28 percent in 2005.
2 Though when it was renewed, it applied retroactively so any project that went into operation received the
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Natural Gas
Figure 3- 6. Electricity Generation in Arizona by Source, 2005 ( Source: EIA).
1990 1992 1994 1996 1998 2000 2002 2004
Electricity Generation, TWh
Figure 3- 7. Electricity Generation in Arizona 1990- 2005 ( Source: EIA).
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3.2.1 Existing and Announced Renewable Energy Projects
Although renewables currently only comprise a small fraction of the electricity in
Arizona, this will likely change in the near future. Table 3- 2 shows existing and
announced renewable energy projects ( excluding large hydroelectric projects). There are
about 24 MW of renewable energy projects currently operating in Arizona, including 12
MW of biomass, 0.8 MW hydroelectric, and the remainder solar ( 11 MW). In addition,
there are over 500 MW of projects in various stages of development throughout the state.
The vast majority of these projects are based on wind resources, although there is a 20
MW biomass project under construction in eastern Arizona.
3.2.2 Arizona Renewable Energy Standard3
Arizona was one of the earlier states to adopt a renewable portfolio standard
mandating that utilities source a portion of their energy from renewable energy sources.
Arizona enacted its original Environmental Portfolio Standard ( EPS) in March of 2001.
The EPS required that investor owned utilities provide 1.1 percent of their power from
renewables by 2007. The standard began with a requirement of 0.2 percent in 2002,
increasing by 0.2 percent annually. Solar electric was to make up 50 percent of the
standard in 2001, increasing to 60 percent for 2004 through 2012. Although the EPS was
largely responsible for several of the projects identified in the previous section, many felt
that the mandate needed to be revised.
After much deliberation, on November 14th, 2006 the Arizona Corporation
Commission ( ACC) adopted a new Renewable Energy Standard ( RES) that requires
utilities to meet higher targets for renewable energy sources. The requirement begins at
1.25 percent renewables in 2006 and stair- steps up to 15 percent renewable energy
production by 2025 ( see Table 3- 3). A certain portion of the RES must be met with
distributed renewable energy generation sources, such as small solar and wind. This is
also known as a set- aside. The set- asides begin at 5 percent of the standard in 2007 and
rise to 30 percent of the renewable standard percentage in 2012 and thereafter. At the full
15 percent standard in 2025, the set- aside would be 30 percent of total renewable
requirement of 15 percent, or 4.5 percent of total electricity generation ( 10.5 is non-distributed
resources). One half of the distributed resource requirement must come from
residential installations, the other half must be from non- residential, non- utility
applications. The purpose of the set- aside is to encourage renewable energy production
from distributed sources such as small solar or wind equipment located on or near
ratepayer property instead of larger, centralized renewable power plants.
3 Source: ACC Decision No. 69127 ( AAC R14- 2- 1801 et seq.), available at:
http:// www. cc. state. az. us/ utility/ electric/ res. pdf, accessed January 2007.
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Table 3- 2. Renewable Energy Projects in Arizona.
Technology / Project Name Owner MW COD
Los Reales Landfill Cofiring TEP 4 1999
Tri Cities Landfill SRP 5 2001
Eagar Biomass Western Renewable Energy 3.7 to 4.7* 2008*
Skunk Creek Landfill Ameresco 3 2008**
27th Ave. Landfill Cambrian 3 2009**
Snowflake White Mountain Power NZLegacy Energy LLC 24 2008**
Arizona Falls SRP 0.8 2003
Santan Solar SRP 0.097 1998
Santan Solar SRP 0.097 1999
Star APS 0.2 2000
Flagstaff APS 0.08 1997
Ocotillo APS 0.1 1998
Tempe APS 0.18 1998
Gilbert ( AZ) APS 0.12 1999
Municipal Rooftops APS 0.1 1999
Ocotillo APS 0.1 1999
Scottsdale APS 0.03 1999
Microelectronics Rooftop APS 0.02 2000
Glendale APS 0.2 2001
Prescott ERAU Solar APS 0.2 2001
Agua Fria SRP 0.2 2001
Yucca APS 0.1 2001
Prescott Airport Solar Plant APS 3.4 2002- 06
Springerville Generating Station TEP 5.1 2002- 03
Saguaro APS 1 2005
Steel Park Wind Western Wind Energy 15 2007**
Sunshine Wind Energy Park Foresight Energy Co 60 2007**
Sunset Mountains Wind Hopi Tribe ( The) 100 2007**
Dry Lake Wind PPM Energy Inc 99 2008**
Steel Park Wind Western Wind Energy 100 2008**
Steel Park Wind Western Wind Energy 100 2009**
Total Existing 24
Total Proposed 504
Source: Utilities, GED
* Generator is 4.7MW, boiler damaged, was not capable of powering the generator at 4.7MW.
May replace with larger boiler.
** Planned / Proposed Projects ( COD subject to change).
*** None of the wind projects are currently under contract to sell power.
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Table 3- 3. Arizona Renewable Energy Standard Requirements.
RES Total
Share of RES
Share of Total
Non- Distributed
Share of Total
2006 1.25% 0.0% 0.0% 1.3%
2007 1.50% 5.0% 0.1% 1.4%
2008 1.75% 10.0% 0.2% 1.6%
2009 2.0% 15.0% 0.3% 1.7%
2010 2.5% 20.0% 0.5% 2.0%
2011 3.0% 25.0% 0.8% 2.3%
2012 3.5% 30.0% 1.1% 2.5%
2013 4.0% 30.0% 1.2% 2.8%
2014 4.5% 30.0% 1.4% 3.2%
2015 5.0% 30.0% 1.5% 3.5%
2016 6.0% 30.0% 1.8% 4.2%
2017 7.0% 30.0% 2.1% 4.9%
2018 8.0% 30.0% 2.4% 5.6%
2019 9.0% 30.0% 2.7% 6.3%
2020 10.0% 30.0% 3.0% 7.0%
2021 11.0% 30.0% 3.3% 7.7%
2022 12.0% 30.0% 3.6% 8.4%
2023 13.0% 30.0% 3.9% 9.1%
2024 14.0% 30.0% 4.2% 9.8%
2025 15.0% 30.0% 4.5% 10.5%
Eligible renewable resources include:
• Biogas electricity generator
• Biomass electricity generator
• Hydroelectric
• Existing hydroelectric upgrades
• Existing hydroelectric used to " firm" other eligible resources
• New small hydroelectric ( 10 MW or less)
• Fuel cells that use only renewable fuels
• Geothermal generator
• Landfill gas generator
• Solar electricity resources
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• Wind generator
• Hybrid wind and solar
In addition, various distributed generation technologies qualify for the distributed
resource set- aside. These include solar daylighting, solar pool water heaters, solar
HVAC, combined heat and power ( CHP) and other on- site technologies. However, these
technologies were not investigated in this report, since the focus is on the non- distributed
share of the RES.
It should be noted that only the regulated utilities are covered by the ruling. This
includes investor owned utilities ( Arizona Public Service and Tucson Electric Power) and
cooperatives. Salt River Project is not required to comply with the RES; however, SRP
has adopted its own renewable energy goals. In 2004, SRP established a voluntary goal
of achieving 15 percent of its energy from renewable energy and energy efficiency by
2025. Currently SRP has obtained 5 percent of its 15 percent goal ( 4 percent renewables,
and 1 percent energy efficiency). The majority of the renewables share is from large
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4.0 Assessment of Renewable Energy Technology Options
This section reviews the general characteristics and costs of renewable energy
technology options for Arizona.
The first step in the development of generation alternatives involves the
identification of generic generation technologies whose technical and cost characteristics
cause them to be worthwhile candidates for inclusion in portfolio plans. The objective of
this section is to characterize the various renewable energy technologies suitable for
application in Arizona. The information contained in this section will be used to screen
technologies for further investigation later in the project.
4.1 Introduction
Technologies to harness renewable energy are diverse and include wind, solar,
biomass, biogas, geothermal, hydroelectric, and ocean energy. Steady advances in
equipment and operating experience spurred by government incentives have lead to many
mature renewable technologies. The technical feasibility and cost of energy from nearly
every form of renewable energy have improved since the early 1980s. However, most
renewable energy technologies struggle to compete economically with conventional
fossil fuel technologies, and in most countries the renewable fraction of total electricity
generation remains small. This is true despite a huge resource base that has potential to
provide many multiples of current electricity demand. Nevertheless, the field is rapidly
expanding from niche markets to making meaningful contributions to the world's
electricity supply.
4.1.1 Technologies Evaluated
This section provides an overview of the following renewable energy options:
1. Solid biomass
1.1 Direct fired
1.2 Cofiring
1.3 Biomass gasification and IGCC
1.4 Plasma arc gasification
2. Biogas
2.1 Anaerobic digestion
2.2 Landfill gas
3. Solar
3.1 Solar photovoltaic
3.2 Solar thermal electric
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4. Hydroelectric
5. Wind
6. Geothermal
7. Fuel cells using renewable fuels
In addition, although it is not a renewable energy technology, compressed air
energy storage can potentially help enable development of intermittent renewable energy
sources, such as wind. The technology is briefly introduced at the end of this chapter.
4.1.2 General Approach to Characterization
Generally, each technology is described with respect to its principles of operation,
applications, resource characteristics, cost and performance, environmental impacts, and
a high level assessment ( non- quantitative) of its development prospects for Arizona. The
alternatives have been presented with a typical range for performance and cost, and the
generic data provided should not be considered definitive estimates. A more detailed
treatment of cost for promising technologies ( including supply curves) is provided later in
this report. The performance and costs are based on a representative size and installation
in Arizona. Estimates are based on Black & Veatch project experience, vendor inquiries,
and a literature review. In addition, an overall levelized cost range for the general
technology type is provided. This levelized cost of energy accounts for capital cost
( including direct and indirect costs), fuel, operations, maintenance, and other costs over
the typical life expectancy of the unit. ( See further description below.) A range of
levelized costs is typically provided. In such cases, the low end of the levelized cost is
based on the higher capacity factors and the lower capital and O& M costs. This approach
is simple from a calculation perspective; however it must be noted that the low end of the
costs represents and ideal " best case scenario", which is likely difficult to achieve in
practice. The high end of the levelized cost is based on the lower capacity factors and the
higher capital and O& M costs. Applicable financial incentives have been included in the
levelized cost calculations, as indicated for each technology. These incentives are
generally described in Section 6.
It should be noted that the characteristics provided in this section are general, and
have been developed for the purposes of providing high- level screening information to
identify the most promising technologies. Section 5 of this report provides estimates
which are project- specific. These estimates are more accurate and representative of
actual projects that could potentially be developed.
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Although a few of the technologies are not commercially viable at this time, cost
and performance data were assembled as available to provide a complete screening- level
resource planning evaluation.
4.1.3 Levelized Cost of Energy Calculation Example
A levelized busbar cost model was constructed to evaluate the cost of each
generating option. A levelized busbar analysis converts both fixed and variable costs to a
single, all- inclusive cost per kilowatt- hour, assuming a given capacity factor4.
Table 4- 1 illustrates the calculation of a busbar cost at a 90 percent capacity factor
for a 35 MW biomass plant based on the capital and operating characteristics developed
in this section and the fixed charge rate assumptions described in Section 7. The columns
of the table present the year- by- year costs in four categories ( capital, fixed O& M,
variable O& M, fuel) based on the input assumptions shown at the top of the table. Any
applicable tax credits are also accounted for on a pre- tax basis. The total annual cost is
determined by applying the levelized fixed charge rate to the initial capital cost. The
fixed O& M is equal to the initial cost plus escalation; variable O& M is based on the
escalated cost and unit production, fuel cost is based on the escalated fuel cost, output
and the net plant heat rate. Busbar costs are equal to the total cost divided by output, and
the present worth cost is based on a 10.1 percent discount rate. At a capacity factor of 90
percent, the table indicates that the busbar cost of the unit is $ 66/ MWh over a 20 year
period. This is a levelization of a 20 year nominal cost and has the following
interpretation: if the busbar costs of the facility were $ 66/ MWh every year of the 2007-
2026 period, the present value of these costs would be the same as the present value of
the variable, year- by- year costs listed in the " Busbar Cost" column of Table 4- 1.
4 Capacity factor is a significant assumption in the busbar cost calculation as it is the basis for determining
the number of kilowatt hours a generating unit will produce, and the unit's all inclusive cost will be spread
over, in a given time period.
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Table 4- 1. Biomass Levelized Cost of Energy Calculation.
Plant Input Data Economic Input Data Rate Escalation
Capital Cost ($ 1,000) 96,250 First Year Fixed O& M ($ 1,000) 2,905.00 2.5%
Total Net Capacity ( MW) 35.00 First Year Variable O& M ($ 1,000) 3,118.12 2.5%
Capacity Factor 90% Fuel Rate ($/ MBtu) 1.00 2.5%
Full Load Heat Rate, Btu/ kWh ( HHV) 1 3,500.00 Tax Credit ($/ MWh) 16.56 2.5%
Debt Term 15
Project Life 20
Present Worth Discount Rate 10.1%
Hours per Year 8,760 Levelized Fixed Charge Rate 12.00%
($ 1,000)
Fixed O& M
($ 1,000)
($ 1,000)
Tax Credit
($ 1,000)
Fuel Rate
($/ MBtu)
Fuel Cost
($ 1,000)
Total Cost
($ 1,000)
PW Total
($ 1,000)
Busbar Cost
($/ MWh)
PW Cost
($/ MWh)
($/ kW)
($/ MWh)
2007 11,550 2,905 3,118 ( 4,570) 1.00 3,725 16,729 15,194 60.62 55.06 0.00 111.89
2008 11,550 2,978 3,196 ( 4,684) 1.03 3,818 16,858 13,907 61.09 50.40 0.00 121.46
2009 11,550 3,052 3,276 ( 4,801) 1.05 3,914 16,991 12,731 61.57 46.14 0.00 131.10
2010 11,550 3,128 3,358 ( 4,921) 1.08 4,012 17,127 11,655 62.07 42.24 0.00 133.40
2011 11,550 3,207 3,442 ( 5,044) 1.10 4,112 17,266 10,672 62.57 38.68 0.00 139.93
2012 11,550 3,287 3,528 ( 5,170) 1.13 4,215 17,409 9,774 63.09 35.42 160.34 146.48
2013 11,550 3,369 3,616 ( 5,299) 1.16 4,320 17,556 8,952 63.62 32.44 162.00 155.09
2014 11,550 3,453 3,706 ( 5,432) 1.19 4,428 17,706 8,200 64.17 29.72 160.15 159.54
2015 11,550 3,539 3,799 ( 5,568) 1.22 4,539 17,860 7,513 64.72 27.23 192.08 155.25
2016 11,550 3,628 3,894 ( 5,707) 1.25 4,652 18,018 6,884 65.30 24.95 192.80 164.57
2017 11,550 3,719 3,991 1.28 4,769 24,029 8,338 87.08 30.22 192.35 168.47
2018 11,550 3,812 4,091 1.31 4,888 24,341 7,672 88.21 27.80 183.14 166.80
2019 11,550 3,907 4,194 1.34 5,010 24,660 7,059 89.37 25.58 203.74 163.22
2020 11,550 4,005 4,298 1.38 5,135 24,988 6,497 90.56 23.54 200.11 168.86
2021 11,550 4,105 4,406 1.41 5,264 25,324 5,980 91.77 21.67 196.32 159.73
2022 - 4,207 4,516 1.45 5,395 14,118 3,028 51.16 10.97 214.88 164.41
2023 - 4,312 4,629 1.48 5,530 14,471 2,819 52.44 10.22 202.03 166.83
2024 - 4,420 4,745 1.52 5,668 14,833 2,625 53.76 9.51 206.07 170.16
2025 - 4,531 4,863 1.56 5,810 15,204 2,443 55.10 8.85 210.19 173.57
2026 - 4,644 4,985 1.60 5,955 15,584 2,275 56.48 8.24 214.40 177.04
2027 - - - - - - - 0.00 0.00 0.00 0.00
2028 - - - - - - - 0.00 0.00 0.00 0.00
2029 - - - - - - - 0.00 0.00 0.00 0.00
2030 - - - - - - - 0.00 0.00 0.00 0.00
2031 - - - - - - - 0.00 0.00 0.00 0.00
2032 - - - - - - - 0.00 0.00 0.00 0.00
2033 - - - - - - - 0.00 0.00 0.00 0.00
2034 - - - - - - - 0.00 0.00 0.00 0.00
2035 - - - - - - - 0.00 0.00 0.00 0.00
2036 - - - - - - - 0.00 0.00 0.00 0.00
2037 - - - - - - - 0.00 0.00 0.00 0.00
2038 - - - - - - - 0.00 0.00 0.00 0.00
2039 - - - - - - - 0.00 0.00 0.00 0.00
2040 - - - - - - - 0.00 0.00 0.00 0.00
2041 - - - - - - - 0.00 0.00 0.00 0.00
2042 - - - - - - - 0.00 0.00 0.00 0.00
2043 - - - - - - - 0.00 0.00 0.00 0.00
2044 - - - - - - - 0.00 0.00 0.00 0.00
2045 - - - - - - - 0.00 0.00 0.00 0.00
2046 - - - - - - - 0.00 0.00 0.00 0.00
2047 - - - - - - - 0.00 0.00 0.00 0.00
2048 - - - - - - - 0.00 0.00 0.00 0.00
2049 - - - - - - - 0.00 0.00 0.00 0.00
2050 - - - - - - - 0.00 0.00 0.00 0.00
2051 - - - - - - - 0.00 0.00 0.00 0.00
2052 - - - - - - - 0.00 0.00 0.00 0.00
2053 - - - - - - - 0.00 0.00 0.00 0.00
2054 - - - - - - - 0.00 0.00 0.00 0.00
2055 - - - - - - - 0.00 0.00 0.00 0.00
2056 - - - - - - - 0.00 0.00 0.00 0.00
Low Cost Case
Levelized Bus- bar Cost, $/ MWh
Net Levelized Cost ($ 1,000)
Biomass Direct Combustion
Calculating the levelized cost of energy allows various technologies to be
compared on an economic basis. However, it is important to note that busbar costs may
not always be comparable between all options. For example, it is not appropriate to
directly compare the levelized cost of an intermittent wind plant with dispatchable output
from a peaking plant. This is because the economic value of the peaking plant is higher
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than the time variant output from the wind plant. Additionally, transmission costs have
not been included in the generalized levelized cost of energy calculations and these
should be considered when comparing specific projects against one another.
4.2 Solid Biomass
Biomass is any material of recent biological origin; the most common form is
wood. Electricity generation from biomass is the second most prolific source of
renewable electric generation after hydroelectric power. Solid biomass power generation
options include direct- fired biomass, biomass gasification, and cofired biomass, as
described in the following subsections. This section concludes with a summary of
development prospects for biomass in Arizona.
4.2.1 Direct- Fired Biomass
According to the US Department of Energy, there is about 35,000 MW of
installed biomass combustion capacity worldwide. Combined heat and power
applications in the pulp and paper industry comprise the majority of this capacity ( Figure
4- 1).
Figure 4- 1. 35 MW Biomass Combustion Plant.
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Operating Principles
Direct biomass combustion power plants in operation today use the same steam
Rankine cycle that was introduced commercially 100 years ago. In many respects,
biomass power plants are similar to coal plants. When burning biomass, pressurized
steam is produced in a boiler and then expanded through a turbine to produce electricity.
Prior to its combustion in the boiler, the biomass fuel may require processing to improve
the physical and chemical properties of the feedstock. Furnaces used in biomass
combustion include spreader stoker fired, suspension fired, fluidized bed, cyclone, and
pile burners. Advanced technologies, such as integrated biomass gasification combined
cycle ( IGCC), Plasma Gasification and biomass pyrolysis, are currently under
Although wood is the most common biomass fuel, other biomass fuels include
agricultural residues such as bagasse ( sugar cane residues), dried manure and sewage
sludge, black liquor from pulp mills, and dedicated fuel crops such as fast growing
grasses and eucalyptus.
Biomass plants usually have a capacity of less than 50 MW because of the
dispersed nature of the feedstock and the large quantities of fuel required. As a result of
the smaller scale of the plants and lower heating values of the fuels, biomass plants are
commonly less efficient than modern fossil fuel plants. In addition to being less efficient,
biomass is generally more expensive than conventional fossil fuels on a $/ MBtu basis
because of added transportation costs. These factors usually limit the use of direct- fired
biomass technology to inexpensive or waste biomass sources.
Resource Availability
To be economically feasible, dedicated biomass plants are located either at the
source of a fuel supply ( such as at a sawmill) or within 50 miles of numerous suppliers
( up to 200 miles for a very high quantity, low cost supplier). Wood and wood waste are
the primary biomass resources and are typically concentrated in areas of high forest-product
industry activity. In rural areas, agricultural production can often yield
significant fuel resources that can be collected and burned in biomass plants. These
agricultural resources include bagasse, corn stover, rice hulls, wheat straw, and other
residues. Energy crops, such as switchgrass and short rotation woody crops, have also
been identified as potential biomass sources. In urban areas, biomass is typically
composed of wood wastes such as construction debris, pallets, yard and tree trimmings,
and railroad ties. Locally grown and collected biomass fuels are relatively labor intensive
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and can provide substantial employment benefits to rural economies. In general, the
availability of sufficient quantities of biomass is less of a feasibility concern than the high
costs associated with transportation and delivery of the fuel.
Based on recent biomass resource assessments that Black & Veatch is familiar
with, the expected cost of clean wood residues can vary as much as 100 percent
depending on the type of residue, quantity, and hauling distance.
Cost and Performance Characteristics
Table 4- 2 presents the typical characteristics of a 35 MW stoker boiler biomass
plant with Rankine cycle using wood as fuel. Two fuel costs scenarios were evaluated:
( 1) a relatively lower cost ($ 1.00/ MBtu) scenario which would be based primarily on
urban wood waste sources in the major metropolitan areas, and ( 2) a moderate cost
($ 2.50/ MBtu) scenario which would be more representative of a project using forest
thinnings and forestry residues. Actual fuel cost could vary significantly from the values
characterized here based on local supply and demand, and transportation distance. For
example, Black & Veatch has previously estimated costs for biomass resources at greater
than $ 3/ MBtu in some parts of Arizona. In this case, transport distances were up to 200
miles. ( Additional discussion is provided in Section 5.) Another possible biomass fuel is
dedicated energy crops, which are grown specifically to provide feedstock for biomass
plants. However, experience with energy crops is very limited in Arizona; further, costs
for these fuels would likely approach $ 4.00/ MBtu or greater. For these reasons,
electricity costs for energy crops are not provided.
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Table 4- 2. Direct- Fired Biomass Combustion Technology Characteristics.
Typical Duty Cycle Baseload
Net Plant Capacity ( MW) 35
Net Plant Heat Rate ( HHV, Btu/ kWh) 13,500
Capacity Factor ( percent) 70 to 90
Economics ( 2007$)
Total Project Cost ($/ kW) 2,750 to 3,500
Fixed O& M ($/ kW- yr) 83
Variable O& M ($/ MWh) 11.3
Levelized Cost, $ 1.00/ MBtu ($/ MWh) 66 to 94
Levelized Cost, $ 2.50/ MBtu ($/ MWh) 90 to 118
Applicable Incentives Open loop: $ 10/ MWh PTC, 5- yr MACRS
Close loop: $ 20/ MWh PTC, 5- yr MACRS
Technology Status
Commercial Status Commercial
Installed US Capacity ( MW) 7,000
Environmental Impacts
Biomass power projects must maintain a careful balance to ensure long- term
sustainability with minimal environmental impact. Most biomass projects target
utilization of biomass waste material for energy production, saving valuable landfill
space. Biomass projects that burn forestry or agricultural products must ensure that fuel
harvesting and collection practices are both sustainable and do not adversely affect the
environment. On the positive side, biomass projects that collect thin forests to reduce the
risk of forest fires are increasingly seen as a way to restore a positive balance to forest
ecosystems while avoiding catastrophic and polluting uncontrolled forest fires.
Unlike fossil fuels, biomass is viewed as a carbon- neutral power generation fuel.
While carbon dioxide ( CO2) is emitted during biomass combustion, a nearly equal
amount of carbon dioxide is absorbed from the atmosphere during the biomass growth
phase. Further, biomass fuels contain little sulfur compared to coal and therefore produce
less sulfur dioxide ( SO2). Finally, unlike coal, biomass fuels typically contain only trace
amounts of toxic metals, such as cadmium and lead. However, biomass combustion still
must include technologies to control emissions of nitrogen oxides ( NOx), particulate
matter ( PM), and carbon monoxide ( CO) to maintain Best Available Control Technology
( BACT) standards.
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Arizona Biomass Combustion Outlook
The outlook for biomass combustion technologies is provided in Section 4.2.5
Biomass Technologies Development Prospects.
4.2.2 Biomass Gasification and IGCC
Biomass gasification is an emerging technology that converts solid biomass into a
gaseous fuel which can then be combusted or otherwise utilized. There are numerous
uses for the gas and many different gasifier technologies. Integrated gasification
combined cycle ( IGCC) is a developing application that combines a gasifier with a
conventional combined cycle power plant ( combustion turbine followed by a steam
cycle). All of the 19 demonstration scale of IGCC plants constructed worldwide have
been fossil- fueled. There are no integrated gasification combined cycle plants currently
operating with biomass as a primary fuel.
Operating Principles
Biomass gasification is a process to convert solid biomass into a gaseous fuel.
This is accomplished by heating the biomass in an environment low in oxygen (" fuel
rich"). Gasification is a promising process for biomass conversion. By converting solid
fuel to a combustible gas, gasification enables the use of more advanced, efficient and
environmentally benign energy conversion processes such as gas turbines and fuel cells
to produce power, and chemical synthesis to produce ethanol and other value added
products. There is a huge variety of gasification technologies including updraft,
downdraft, fixed grate, entrained flow, fluidized bed, and molten metal baths. The
technology choice depends primarily on the fuel characteristics and the desired capacity
of the plant.
Most biomass gasification systems are air blown. The primary product of air-blown
gasification is a low heating value fuel gas, typically 15 to 20 percent ( 150- 200
Btu/ ft3) of the heating value of natural gas ( 1,000 Btu/ ft3). Using oxygen, steam, or
indirect heating results in a higher quality gas, although at higher costs.
The primary advantage of gasification over direct combustion is the versatility of
the gasification product. Gasification expands the use of solid fuel to include practically
all the uses of natural gas and petroleum, including close- coupled boilers, combustion
engines and turbines, fuel cells, and chemical synthesis, and Stirling engines. The
various fuel gas conversion options are illustrated in Figure 4- 2.
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Final Products
Medium Energy
Low Energy
CO, H2, CH4, CxHy, tars
Conversion Technology Primary Products
Fuel Cell
Gas Engine
Gas Turbine
Boiler / Steam
Secondary Conversion
Ash Residues
Air /
Steam /
Ammonia, etc
Figure 4- 2. General Gasification Flow.
One of the principal focus areas for biomass gasification technology developers
has been biomass IGCC. In an IGCC plant, the syngas exiting the gasifier is cleaned and
combusted in a combustion turbine, generating power. Waste heat from the gas turbine is
used to generate steam for use in a Rankine steam cycle. Net conversion to electricity for
biomass IGCC plants is projected to be approximately 35 percent, compared to 20 to 25
percent for direct fired biomass plants. The potentially significant increase in efficiency
makes biomass IGCC attractive; however, problems experienced with technology
demonstration will need to be overcome. Although there are many gasifiers installed that
produce fuel gas for close- coupled combustion in a boiler ( essentially staged
combustion), recent attempts to demonstrate more advanced processes, such as IGCC,
have not been successful. Issues have been related partially to the gasification process
itself, but also to supporting ancillary equipment, such as fuel handling and gas cleanup.
Regardless, there are several biomass gasification equipment suppliers, including Foster
Wheeler, Energy Products of Idaho, and Primenergy, which continue to develop biomass
gasification technology for other applications.
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Resource Availability
A biomass gasification or biomass IGCC plant would have similar resource
availability issues as a direct- fired biomass plant. To be economically feasible it should
be located either at the source of a fuel supply or within 50 to 75 miles of numerous
suppliers. Wood, wood byproducts, agricultural residues, energy crops, and urban wood
wastes are all suitable fuels for a biomass IGCC plant.
Like other biomass conversion technologies, an IGCC biomass plant would be
limited in capacity by the amount of resource which could feasibly be delivered. A
reasonable estimate for this limit is 30 MW to 75 MW, depending on location.
Conversely, coal IGCC power plants are typically limited by the gas turbine capacity, not
by fuel availability, and can be designed for much larger capacities similar to other fossil
fuel power plants.
Cost and Performance Characteristics
Given the lack of commercial experience, cost and performance estimates for an
IGCC biomass plant are uncertain. Since it would be limited to a size much smaller than
an IGCC coal plant, an IGCC biomass plant would not benefit from the economies of
scale of such plants. Table 4- 3 presents projected characteristics for a biomass IGCC
combustion plant for urban wood waste and forest residues.
Environmental Impacts
A biomass IGCC biomass project would have the same long- term sustainability
concerns as other biomass conversion technologies. Biomass is viewed as a carbon-neutral
power generation fuel. While CO2 is emitted during biomass conversion, a nearly
equal amount of CO2 is absorbed from the atmosphere during the biomass growth phase.
Further, biomass fuels contain little sulfur compared to coal and therefore produce less
SO2. Finally, unlike coal, biomass fuels typically contain only trace amounts of toxic
metals, such as cadmium, and lead. Biomass gasification technologies will require
equipment to control emissions of NOx, PM, and CO to maintain air emission standards.
It is important to note that given that biomass IGCC is expected to have higher efficiency
than biomass combustion- based power plants, the pounds of pollution per MWh
generated are substantially less.
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Table 4- 3. Biomass IGCC Technology Characteristics.
Typical Duty Cycle Baseload
Net Plant Capacity ( MW) 35
Net Plant Heat Rate ( Btu/ kWh) 10,000 to 11,500
Capacity Factor ( percent) 70 to 90
Economics ($ 2007)
Total Project Cost ($/ kW) 3,000 to 4,000
Fixed O& M ($/ kW- yr) 83
Variable O& M ($/ MWh) 10.7
Levelized Cost, $ 1.00/ MBtu ($/ MWh) 65 to 99
Levelized Cost, $ 2.50/ MBtu ($/ MWh) 82 to 120
Applicable Incentives Open loop: $ 10/ MWh PTC, 5- yr MACRS
Closed loop: $ 20/ MWh PTC, 5- yr MACRS
Technology Status
Commercial Status Demonstration
Installed US Capacity ( MW) 0
4.2.3 Biomass Cofiring
One of the most economical methods to burn biomass is to cofire it with coal in
existing plants. Cofired projects are usually implemented by retrofitting a biomass fuel
feed system to an existing coal plant, although greenfield facilities can also be designed
to accept a variety of fuels.
As discussed in the previous section, a major challenge to biomass power is that
the dispersed nature of the feedstock and high transportation costs generally preclude
plants larger than 50 MW. By comparison, coal power plants rely on the same
fundamental power conversion technology but can have much higher unit capacities,
exceeding 1,000 MW. As a result of this larger capacity, modern coal plants are able to
obtain higher efficiency at lower cost. Through cofiring, biomass benefits from this
higher efficiency through a more competitive cost than a stand- alone, direct- fired
biomass plant.
It should be noted that electricity demand in Arizona is increasing faster than any
other state. Biomass cofiring converts capacity to a renewable source rather than adds
capacity, and thus may be less attractive than alternatives to add capacity.
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There are several methods of biomass cofiring that can be used to produce energy
on a commercial scale. Provided that they were initially designed with some fuel
flexibility, stoker and fluidized bed boilers generally require minimal modifications to
accept biomass. For these types of boilers, simply mixing the fuel into the coal pile may
be sufficient to cofire biomass.
Figure 4- 3. Coal and Wood Mix.
Cyclone boilers and pulverized coal ( PC) boilers ( the most common in the utility
industry) require smaller fuel sizes than stokers and fluidized beds and may necessitate
processing of the biomass before combustion. There are two basic approaches to cofiring
in this case: co- feeding the biomass through the coal processing equipment or separately
processing and then injecting the biomass in the boiler. The first approach blends the
fuels and feed them together to the coal processing equipment ( crushers, pulverizers,
etc.). In a cyclone boiler, up to 10 percent of the coal heat input can be replaced with
biomass using this method. Pulverizers in a PC boiler are not designed to process
relatively low density biomass, and fuel replacement is generally limited to around 2 or 3
percent if the fuels are mixed. The second approach ( separate biomass processing and
injection) allows higher cofiring percentages ( 10 to 15 percent) in a PC unit but costs
more than processing a fuel blend.
Even at these limited cofiring rates, plant owners and operators have raised
numerous concerns about the negative effects of cofiring on plant operations. These
include the following:
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• Reduced plant capacity.
• Reduced boiler efficiency.
• Ash contamination decreasing the quality of coal ash.
• Increased O& M costs.
• Minimal NOx reduction potential ( usually proportional to biomass heat input).
• Boiler fouling/ slagging because of the high alkali in biomass ash ( more of a
concern with fast growing biomass, such as energy crops).
• Potentially negative effects on SCR air pollution control equipment ( catalyst
• Reopening existing air permits.
These concerns have hampered the widespread adoption of biomass cofiring by
electric utilities in the United States. However, these concerns can often be addressed
through proper system design, fuel selection, and limits on the amount of cofiring.
Coal and biomass cofiring can also be considered in the design of new power
plants. Designing the plant to accept a diverse fuel mix allows the boiler to incorporate
biomass fuel, ensuring high efficiency with low O& M impacts. Fluidized bed technology
is often the preferred boiler technology for cofiring since it has inherent fuel flexibility.
There are many fluidized bed units around the world that burn a wide variety of fuels,
including biomass. An example is a 240 MW circulating fluidized bed ( CFB) in Finland,
which burns a mixture of wood, peat, and lignite. This unit is capable of burning various
fuels, ranging from 100 percent biomass to 100 percent coal.
Resource Availability
For viability, the candidate coal plant should be located within 100 miles of
suitable biomass resources. The United States has a larger installed biomass power
capacity than any other county in the world. The United States- based biomass power
plants provide 7,000 MW of capacity to the national power grid. Coal power generation
accounted for 2 trillion kWh in 2005, which comprised 49.7 percent of the total
generation in the United States. Conversion of as little as 5 percent of this generation to
biomass cofiring would increase electricity production from biomass by nearly 400
percent. It is important to note that biomass cofiring projects typically do not result in
capacity increases as do other renewables. Instead, they offset fuel use at existing plants.
Cost and Performance Characteristics
Table 4- 4 presents the typical characteristics for a biomass and coal cofired plant.
The characteristics are based on cofiring 35 MW of biomass ( separate injection) in a 400
MW pulverized coal power project. Except for fuel, the characteristics are provided on
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an incremental basis ( changes that would be expected compared to the coal plant). The
primary capital cost for the project would be related to the biomass material handling
system. As with direct fired biomass, biomass fuel cost is assumed to range from
$ 1.00/ MBtu for urban wood residues to $ 2.50/ MBtu for forestry residues. To calculate
the incremental fuel cost, coal has been assumed at a base cost of $ 1.50/ MBtu. The
incremental biomass cost is then ($ 0.50/ MBtu) to $ 1.00/ MBtu. Thus on the low- end, the
biomass fuel cost is actually assumed to be $ 0.50/ MBtu less expensive than coal.
Analysis of the range of incremental levelized costs presented in Table 4- 4
indicates that the costs to cofire biomass with coal would be relatively small. The range
of incremental levelized costs is between approximately $ 0/ MWh ( no increase) to
$ 9/ MWh for urban wood waste ( assumed to cost $ 1/ MBtu, which is $ 0.50/ MBtu less
than coal), and $ 18/ MWh to $ 27/ MWh for forest residues ( assumed to cost $ 2.50/ MBtu,
which is $ 1/ MBtu more than coal). This can be interpreted as the additional cost to
produce one MWh of biomass energy, over the cost of coal power.
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