NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

Renewable Energy Optimization 

Report for Naval Station 

Newport

A Study Prepared in Partnership with the 

Environmental Protection Agency for the 

RE-Powering America’s Land Initiative: 

Siting Renewable Energy on Potentially 

Contaminated Land and Mine Sites

Robi Robichaud, Gail Mosey, and Dan Olis

Technical Report

NREL/TP-6A20-48852

February 2012
NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

National Renewable Energy Laboratory

1617 Cole Boulevard

Golden, Colorado 80401

303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

Renewable Energy 

Optimization Report for Naval 

Station Newport

A Study Prepared in Partnership with the 

Environmental Protection Agency for the 

RE-Powering America’s Land Initiative: 

Siting Renewable Energy on Potentially 

Contaminated Land and Mine Sites

Robi Robichaud, Gail Mosey, and Dan Olis

Prepared under Task No. WFD5.1000

Technical Report

NREL/TP-6A20-48852

February 2012
NOTICE

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iii

Acknowledgments

This effort was sponsored by the Environmental Protection Agency (EPA). Information 

regarding the location of each facility, utility use, and cost information was provided by 

John Reichert, Energy Engineer at Naval Station Newport. NREL staff members 

involved were Robi Robichaud, principal investigator, and Gail Mosey, NREL’s project 

lead for the EPA RE-Powering America’s Lands programs. Dan Olis conducted the 

Renewable Energy Optimization (REO) computer analysis with the updated version of 

the tool and applied it to the GIS resources analysis and application of incentives offered 

for each technology originally completed by James Bright and Kate Anderson. Andy 

Walker provided technology descriptions and REO analysis methodology. Jason Fields 

provided wind turbine sizing and rating information.
iv

List of Acronyms

AD anaerobic digestion

ASHRAE American Society of Heating, Refrigerating 

and Air-Conditioning Engineers

BOS balance of system

BTU British thermal unit

CBECS Commercial Building Energy Consumption 

Survey

CHP combined heat and power

CO carbon monoxide

CO2 carbon dioxide

COE cost of energy

COP coefficient of performance

DAS data acquisition system

DOE U.S. Department of Energy

ECIP Energy Conservation and Investment 

Program

EER energy efficiency ratio

EPA U.S. Environmental Protection Agency

EPAct 2005 Energy Policy Act of 2005

ESPC energy savings performance contract

FAA Federal Aviation Administration

FY fiscal year

GHG greenhouse gas

GHP geothermal heat pump

GIS geographic information systems

GSHP ground source heat pump

GT diurnal range

HDPE high density polyethylene

HRSG heat-recovery steam generator

HVAC heating, ventilation, and air-conditioning

IESNA Illuminating Engineering Society of North 

America

IGCC integrated gasification and combined cycle

ITC investment tax credit

LCC life cycle cost

LFG landfill gas

MBH thousands of British thermal units per hour

MCFC molten carbonate fuel cell

MCP Measure-Correlate-Predict

MN mean range

MSW municipal solid waste

N2O nitrous oxide

NAVSTA naval station
v

NFESC Naval Facilities Engineering Service Center

NIST National Institute of Standards and 

Technology

NMOC non-methane organic compound

NOAA National Oceanic and Atmospheric 

Administration

NOx nitrogen oxide

NPDES National Pollutant Discharge Elimination 

System

NREL National Renewable Energy Laboratory

O&M operation and maintenance

PCB polychlorinated biphenyl

PV photovoltaics

PVC polyvinyl chloride

R&D research and development

RE renewable energy

REO Renewable Energy Optimization

ROI return on investment

SODAR sonic detection and ranging

SPB simple payback

SVP solar ventilation preheating

UESC utility energy services contract

USDA U.S. Department of Agriculture

VOC volatile organic compound

VWSF vertical wind shear factor

Wp peak Watt

WRA wind resource assessment
vi

Executive Summary

In 2008, the U.S. Environmental Protection Agency (EPA) launched the RE-Powering 

America’s Land initiative to encourage the development of renewable energy (RE) on 

potentially contaminated land and mine sites. As part of this effort, EPA is collaborating 

with the U.S. Department of Energy’s (DOE’s) National Renewable Energy Laboratory 

(NREL) to evaluate RE options at Naval Station (NAVSTA) Newport in Newport, Rhode 

Island.

NREL’s Renewable Energy Optimization (REO) tool was utilized to identify RE

technologies that present the best opportunity for life-cycle cost-effective implementation 

while also serving to reduce energy-related carbon dioxide emissions and increase the 

percentage of RE used at NAVSTA Newport. The technologies included in REO are

daylighting, wind, solar ventilation preheating (SVP), solar water heating, photovoltaics 

(PV), solar thermal (heating and electric), and biomass (gasification and cogeneration). 

The optimal mix of RE technologies depends on several factors including RE resources; 

technology cost and performance; state, utility, and federal incentives; and economic 

parameters (discount and inflation rates). Each of these factors was considered in this 

analysis. Technologies not included in REO that were investigated separately per 

NAVSTA Newport request include biofuels from algae, tidal power, and ground source 

heat pumps (GSHP).

Improving overall energy efficiency is often the most cost-effective first step in 

implementing RE technologies. NAVSTA Newport has undertaken a number of energy 

efficiency audits and retrofits over the years and constructs new buildings with high 

efficiency goals. They desire to produce 25% of its base energy from life cycle cost 

(LCC) effective renewable sources. The base case of continuing to purchase electricity 

and natural gas has zero initial cost but high annual cost, while the RE solutions case has 

high initial cost but reduced annual cost and a reduced LCC. Based on NREL analysis, 

the REO results indicate that a RE solutions case combines wind turbines, SVP, solar 

water heating, and daylighting, which minimize the LCC of RE technologies at NAVSTA 

Newport. The results for the RE solutions case can be seen in Table ES-1. 
vii

Table ES-1. Sizes and Performance of Cost-Effective Renewable Energy Technologies

under the RE Solutions Case

Figure ES-1 compares the overall size and potential energy offset of each technology in 

the base case and the RE solutions case. Annual energy delivery of each technology is 

shown in equivalent energy of million British thermal units per year.

Figure ES-1. Energy delivery of each renewable energy technology per minimum life cycle 

cost

Table ES-2 provides a summary of the RE produced by these systems in equivalent 

kilowatt-hour terms; initial cost to implement the optimized RE solution with and without 

incentives; annual utility cost savings associated with those measures; and simple 

payback period with and without incentives. The REO analysis shows that the optimal 

Technology Size Units Electricity 

Offset

Percent 

Electricity 

Reduction

Fuel 

Offset

Percent 

Fuel 

Reduction

Annual 

Emission 

Reduction

25 - Year 

Emission 

Reduction

kWh/yr % therms/yr % lbs CO2/yr lbs CO2

Skylight/ Floor Area Ratio 1.4% % 2,244,628 2.1% -59,755 -1.2% 1,279,850 31,996,259

Wind Energy 9,000 kW 23,843,000 22.5% - - 21,019,315 525,482,875

Solar Vent Preheat 260,417 f t2 - - 468,632 9.5% 5,481,529 137,038,222

Solar Water Heating 138,409 f t2 - - 465,758 9.4% 5,447,912 136,197,801

PV 0 kW - - - - - -

Concentrating Solar Area 0 f t2 - - - - - -

Concentrating Solar Electric 0 kW - - - - - -

Biomass Gasifier Size 0 MBtu/hr - - - - - -

Biomass Gasifier Cogen Size 0 kW - - - - - -

Totals 26,087,628 24.6% 874,635 17.7% 33,228,606 830,715,157

-5,000

95,000

195,000

295,000

395,000

495,000

595,000

695,000

795,000

Base Case (MMBtu/yr) RE Case (MMBtu/yr)

Annual Energy (MMbtu/yr)

Solar Vent Preheat Sold to Utility Daylighting 

Solar Water Heating Wind Photovoltaics 

Fuel Electric
viii

solution reduces the 25-year cost of energy from around $418 million to $371 million, 

thereby saving about $47 million. An initial investment of around $44 million would be 

required to implement these technologies and would result in utility cost savings of about 

$4 million per year. This project has an 11.9% rate of return and an 11-year simple 

payback period. Implementing these measures would deliver roughly 21.3% of the site’s 

energy use from renewables.

Table ES-2. Renewable Energy Cost and Savings Summary for the RE Solutions Case

Wind is the most cost-effective option at this site with paybacks 35% shorter than the 

next best option. Adding an additional 5.5 MW of wind, bringing the total to 14.5 MW, 

will enable the base to achieve its 25% RE goal. 

NAVSTA Newport asked that additional RE technologies be investigated, such as 

biofuels from algae, tidal power, and GSHPs. These technologies were considered and 

the findings are outlined in the report, but they were not analyzed with the REO tool as 

the modeling parameters are too broad (e.g., extent of resource and costing) to do 

meaningful analysis as done for the other technologies that have more established sizing 

algorithms and more consistent costing parameters. 

The biofuels-from-algae technology is still in the early stages of development with 

optimization efforts focused on many aspects of improving yields, efficiencies, and 

viability by identifying better strains of algae, reducing water consumption while 

growing, and reducing energy consumption while drying/processing the algae into 

biofuel.

For two technologies, GSHP and tidal power, it is premature to make economic estimates 

based on limited knowledge of the extent of the renewable resource. Both require more 

site-specific investigation of the resource before reasonable economic projections and 

recommendations can be made. It is recommended that test bores be undertaken to better 

characterize the geothermal resource for potential GSHP applications. For tidal power, 

two studies are recommended, a bathymetrical study of potential turbines sites in 

Narragansett Bay and, if quality potential sites are identified, a tidal current flow analysis. 

The wind resource data, collected at Coddington Point and Tank Farm #4, was used for a 

separate analysis of 9 MW utility-scale wind turbines at the site. These results were 

added into the REO analysis and are shown in detail in Appendix A.

Technology Equivalent 

Energy 

Offset

Percent 

Energy 

Reduction

Initial 

Investment with 

Incentives

Annual 

Savings

Simple 

Payback

Initial 

Investment 

W/O Incentives

Simple 

Payback

equiv kWh/yr % $ $/yr yrs $ yrs

Daylighting 2,244,628 0.9% 3,261,134 202,747 16.1 3,261,134 16.1

Wind Energy 23,843,000 9.5% 23,940,000 2,790,060 8.6 34,200,000 12.3

Solar Vent Preheat 13,730,918 5.5% 7,746,325 597,402 13.0 11,066,261 18.5

Solar Water Heating 13,646,709 5.4% 9,465,994 497,236 19.0 13,522,848 27.2

Totals 53,465,255 21.3% 44,413,453 4,087,445 11 62,050,243 15
ix 

Table of Contents 

Acknowledgments ...................................................................................................................................... iii

List of Acronyms ........................................................................................................................................ iv

Executive Summary ................................................................................................................................... vi

Table of Contents ....................................................................................................................................... ix

List of Figures ............................................................................................................................................. xi

List of Tables ............................................................................................................................................. xiii

1 Introduction ........................................................................................................................................... 1

2 Background ........................................................................................................................................... 2

2.1 Study Objectives ........................................................................................................................ 3

2.2 Scope of Study ........................................................................................................................... 3

3 Technology Characterizations ............................................................................................................. 5

3.1 Daylighting ................................................................................................................................. 5

3.2 Wind Power ................................................................................................................................ 6

3.3 The Solar Resource ................................................................................................................. 10

3.4 Solar Ventilation Air Preheat .................................................................................................... 12

3.5 Solar Water Heating ................................................................................................................. 15

3.6 Photovoltaics ............................................................................................................................ 17

3.7 Solar Industrial Process Heat and Solar Thermal Electric ....................................................... 20

3.8 Biomass Energy ....................................................................................................................... 22

3.9 Biofuels from Algae .................................................................................................................. 24

3.10 Tidal Power .............................................................................................................................. 25

3.11 Ground Source Heat Pumps .................................................................................................... 28

3.12 Landfill Gas .............................................................................................................................. 32

4 Methodology ........................................................................................................................................ 36

4.1 Utility Energy Usage and Cost Data ........................................................................................ 36

4.2 NAVSTA Newport Site Factors ................................................................................................ 36

4.3 Renewable Resource and Technology Cost Data ................................................................... 36

4.4 Economic Factors .................................................................................................................... 37

4.5 Renewable Energy Optimization .............................................................................................. 37

4.6 Iterative “Solving” ..................................................................................................................... 38

4.7 GIS Data on Renewable Energy Resources ........................................................................... 39

4.8 Optimization Technique ........................................................................................................... 39

4.9 Results of LCC Optimization .................................................................................................... 41

4.10 LCC .......................................................................................................................................... 41

4.11 Carbon Dioxide Emissions Avoided ......................................................................................... 42

4.12 Land Use Requirements .......................................................................................................... 42

5 Data Summaries .................................................................................................................................. 43

5.1 GIS Data .................................................................................................................................. 43

5.2 Incentive Data .......................................................................................................................... 45

5.3 Economic Data ......................................................................................................................... 46

5.4 Site Data .................................................................................................................................. 47

5.5 Technology Data ...................................................................................................................... 47

6 Conclusions and Recommendations ................................................................................................ 54

6.1 Results ..................................................................................................................................... 54

6.2 Conclusions .............................................................................................................................. 56
x 

Appendix A. Coddington Point Wind Data Analysis and Economic Projections ............................... 58

Wind Resource Assessment Activities at NAVSTA Newport ................................................................ 58

Sodar Systems ...................................................................................................................................... 59

Analysis of Collected Wind Data at Coddington Point and Tank Farm #4 ........................................... 60

Wind Turbine Energy Production .......................................................................................................... 74

Appendix B. Solar Vent Preheat Systems ............................................................................................... 79

Solar Vent Preheat System Sizing ........................................................................................................ 79

Appendix C. Solar Hot Water Systems .................................................................................................... 81

Appendix D. Photovoltaic Systems ......................................................................................................... 83

Appendix E. Solar Industrial Process Heat and Solar Thermal Electric .............................................. 85

Appendix F. Biomass Energy ................................................................................................................... 86

Biomass Resource Data ....................................................................................................................... 86

System Sizing and Economics .............................................................................................................. 87

Air Quality Concerns ............................................................................................................................. 88

Appendix G. Tidal Energy ......................................................................................................................... 95

Tidal Resource Assessment ................................................................................................................. 95

Tidal Parameters for Power Production ................................................................................................ 97

Newport Tidal Height and Period Assessment ..................................................................................... 98

Tidal Current Assessment ................................................................................................................... 101

Tidal Current Data ............................................................................................................................... 103

Tidal Power Calculations..................................................................................................................... 104

Appendix H. Geothermal Energy ........................................................................................................... 107

Systems Configuration and Characteristics ........................................................................................ 107

Heat Pumps ........................................................................................................................................ 107

GSHP Economic Parameters ............................................................................................................. 110

Capital Costs ....................................................................................................................................... 110

Operating Costs and Savings Based on Fuel Prices .......................................................................... 111

Operation and Maintenance Costs ..................................................................................................... 113

GSHP Annual Emissions Impacts ....................................................................................................... 113

Newport Soil Characteristics ............................................................................................................... 114

Closed Loop Systems ......................................................................................................................... 116

Open Loop Systems ............................................................................................................................ 119

Newport Soil Analysis ......................................................................................................................... 122

Appendix I. Landfill Gas .......................................................................................................................... 126

Landfill Emissions ............................................................................................................................... 126

Characteristics of Landfills .................................................................................................................. 126

Characteristics of Landfill Gas Power Plants ...................................................................................... 127

Appendix J. NAVSTA Newport Electric Load Data FY 2010 ............................................................... 130

Contacts ................................................................................................................................................... 131

Project Leader ..................................................................................................................................... 131

Principal Investigator ........................................................................................................................... 131

EPA Program Manager ....................................................................................................................... 131

EPA Regional Manager....................................................................................................................... 131
xi

List of Figures

Figure ES-1. Energy delivery of each renewable energy technology per minimum life cycle cost........... vii

Figure 1. Daylighting in Hawaii....................................................................................................................5

Figure 2. Map of U.S. wind resources..........................................................................................................8

Figure 3. Modern wind turbines....................................................................................................................8

Figure 4. Annual daily insolation pattern integrated into a yearly average of sun hours per day ...............10

Figure 5. Atmospheric impacts on diffuse and direct beam insolation .......................................................11

Figure 6. SVP system schematic .................................................................................................................12

Figure 7. SVP system in Leadville, Colorado .............................................................................................13

Figure 8. Map of SVP delivery (depending on both solar and heating requirements) ................................13

Figure 9. Solar hot water heating system schematic ...................................................................................15

Figure 10. Solar water heating system at Chickasaw National Recreation Area, Oklahoma.....................15

Figure 11. Solar electric PV system ............................................................................................................17

Figure 12. PV system schematic .................................................................................................................18

Figure 13. Solar resource across the United States .....................................................................................19

Figure 14. Solar industrial process heat system ..........................................................................................21

Figure 15. Biomass-fueled gasifier and boiler.............................................................................................23

Figure 16. Biomass resources in the United States by tonnage...................................................................23

Figure 17. Aquidneck Island in Narragansett Bay ......................................................................................27

Figure 18. Tidal power turbines ..................................................................................................................28

Figure 19. Seasonal cycles of surface versus underground soil temperatures.............................................31

Figure 20. Average temperature (°C) near the surface of the United States from groundwater 

measurements............................................................................................................................31

Figure 21. McAllister Point Landfill..........................................................................................................33

Figure 22. McAllister Point Landfill with view to the south-west-north arc ..............................................34

Figure 23. Illustration of the solver routine.................................................................................................40

Figure 24. Energy delivery of each renewable energy technology per minimum life cycle cost................55

Figure A-1. Map of NAVSTA Newport with met tower locations.............................................................59

Figure A-2. Coddington Point—Diurnal wind profile ................................................................................64

Figure A-3. Tank farm #4—Diurnal wind profile.......................................................................................64

Figure A-4. Coddington Point boxplot........................................................................................................65

Figure A-5. Tank Farm #4 boxplot..............................................................................................................65

Figure A-6. Overall frequency distribution at Coddington Point................................................................66

Figure A-7. Overall frequency distribution at Tank Farm #4......................................................................66

Figure A-8. Turbulence intensity at Coddington Point ...............................................................................67

Figure A-9. Turbulence intensity at Tank Farm #4 .....................................................................................67

Figure A-10. Wind rose—Total energy by direction at Coddington Point and Tank Farm #4 ...................68

Figure A-11. Monthly wind roses—Total energy by direction at Coddington Point..................................68

Figure A-12 Monthly wind roses—Total energy by direction at Tank Farm #4.........................................69

Figure A-13. Coddington Point and Newport Airport met tower sites........................................................70

Figure A-14. Correlation of concurrent Newport airport data to Coddington Point ...................................71

Figure A-15. Long-term wind profiles at Coddington Point and Tank Farm #4.........................................72

Figure A-16. Mean diurnal profile of Coddington Point.............................................................................73

Figure A-17. Mean diurnal profile of Coddington Point.............................................................................73

Figure B-1. Solar vent preheat cost curve ...................................................................................................80

Figure C-1. Solar hot water cost curve........................................................................................................82

Figure D-1. PV cost curve ...........................................................................................................................84
xii

Figure F-1. Platform 2B biomass gasification with syngas utilization via spark-ignition 

reciprocating engines ................................................................................................................91

Figure F-2. Platform 4A anaerobic digester and spark-ignition engine with heat recovery........................93

Figure G-1. Tide-generating forces based on Earth-moon interactions ......................................................95

Figure G-2. Influence of the moon’s declination on tidal forces.................................................................96

Figure G-3. Graphical depiction of tidal patterns........................................................................................96

Figure G-4. Position of the moon and resultant lunar and solar spring and neap tides...............................97

Figure G-5. Sample tidal current speed distribution....................................................................................98

Figure G-6. Sample turbine output power versus flow speed .....................................................................98

Figure G-7. Newport tide level per mean lower low water—48 hr profile (MLLW) .................................99

Figure G-8. Predicted versus observed tide levels in Newport .................................................................100

Figure G-9. Newport tide level per mean lower low water level—Seven-day profile..............................100

Figure G-10. Newport tide level per mean lower low water level—30-day profile..................................101

Figure G-11. Bathymetry map of Rhode Island ........................................................................................102

Figure G-12. 10 ft (3.1 m) contour map of Narragansett Bay ...................................................................103

Figure H-1. Typical geothermal heat pump configuration ........................................................................108

Figure H-2. Capacity of a typical 4-ton GHP versus EWT.......................................................................109

Figure H-3. Efficiency of a typical 4-ton GHP as a function of EWT......................................................109

Figure H-4. Annual GSHP savings versus cost of natural gas..................................................................111

Figure H-5. Annual GSHP savings versus cost of natural gas..................................................................112

Figure H-6. Annual GSHP savings versus cost of electricity for heating .................................................113

Figure H-7. Scaling potential of groundwater aquifer...............................................................................115

Figure H-8. Horizontal bore, closed loop GSHP system...........................................................................116

Figure H-9. Horizontal bore, closed loop GSHP with spiral coil..............................................................117

Figure H-10. Vertical bore, closed loop GSHP system.............................................................................118

Figure H-11. Closed loop, water-source coil system.................................................................................119

Figure H-12. Open loop lake system at left; open loop system with river or well at right........................120

Figure H-13. Standing column open loop GHP system ............................................................................121

Figure H-14. Vertical open loop water well GHP system.........................................................................121

Figure I-1 Landfill collection system schematic .......................................................................................127
xiii

List of Tables

Table ES-1. Sizes and Performance of Cost-Effective Renewable Energy Technologies under the

RE Solutions Case.................................................................................................................... vii

Table ES-2. Renewable Energy Cost and Savings Summary for the RE Solutions Case ......................... viii

Table 1. Characteristics of Daylighting Technology.....................................................................................6

Table 2. Characteristics of Wind Power Technology....................................................................................9

Table 3. Initial Cost of Components of SVP Technology...........................................................................14

Table 4. Ventilation Rates Used in the Analysis.........................................................................................14

Table 5. Water Heating Load and Characteristics......................................................................................16

Table 6. Characteristics of PV Technology.................................................................................................20

Table 7. Characteristics of Solar Industrial Process Heat Technology .......................................................21

Table 8. Soil Types Defined in the GSHP Model .......................................................................................30

Table 9. Economic Parameters Used in LCC Calculations.........................................................................42

Table 10. GIS Resource Data ......................................................................................................................43

Table 11. Incentives* ..................................................................................................................................45

Table 12. Economic Parameters..................................................................................................................46

Table 13. Site Data ......................................................................................................................................47

Table 14. Daylighting Analysis...................................................................................................................48

Table 15. Wind Analysis.............................................................................................................................49

Table 16. Solar Ventilation Preheating Analysis.........................................................................................49

Table 17. Solar Water Heating Analysis.....................................................................................................50

Table 18. PV Analysis.................................................................................................................................51

Table 19. Concentrating Solar Power Analysis...........................................................................................52

Table 20. Biomass Gasifier Analysis ..........................................................................................................53

Table 21. Estimated Data ............................................................................................................................53

Table 22. Sizes of Cost-Effective Renewable Energy Measures ................................................................54

Table 23. Renewable Energy Solutions Case—Cost and Savings Summary..............................................55

Table A-1. Sensor Configuration at Coddington Point (Site #9202)...........................................................61

Table A-2. Dataset Summary for Coddington Point and Tank Farm #4.....................................................61

Table A-3. Wind Speed Sensor Summary at Coddington Point..................................................................62

Table A-4. Wind Speed Sensor Summary at Tank Farm #4 .......................................................................63

Table A-5. Turbine Power, Class, and Dimension......................................................................................74

Table A-6. Height Tolerance for Potential Wind Turbine Sites..................................................................74

Table A-7. Coddington Point Wind Turbine Annual Energy Production ...................................................75

Table A-8. Tank Farm #4 Wind Turbine Annual Energy Production.........................................................75

Table A-9. Economics of Generic 2.0 MW Wind Turbine at Coddington Point ........................................78

Table F-1. Selected Emissions Data for Each Biomass Conversion Considered ........................................89

Table F-2. Characteristics of Biomass Heat and Power Technologies........................................................94

Table G-1. Predicted Tidal Currents at Quonset Point in Narragansett Bay .............................................104

Table G-2. Power Density at Different Tidal Current Speeds...................................................................106

Table I-1. Waste Energy Consumption .....................................................................................................128

Table I-2. Emissions from Combustion Generation..................................................................................129

Table J-1. NAVSTA Newport Utility Data ...............................................................................................130
1

1 Introduction

In 2008, the U.S. Environmental Protection Agency (EPA) launched the RE-Powering 

America’s Land initiative to encourage the development of renewable energy (RE) on 

potentially contaminated land and mine sites. EPA is encouraging RE development on 

current and formerly contaminated land and mine sites. This initiative identifies the RE

potential of these sites and provides other useful resources for communities, developers, 

industry, state and local governments, or anyone interested in reusing these sites for RE

development. As part of this effort, EPA is collaborating with the U.S. Department of 

Energy’s (DOE’s) National Renewable Energy Laboratory (NREL) to evaluate RE 

options at Naval Station (NAVSTA) Newport in Newport, Rhode Island.

There are approximately 11,000 sites and almost 15 million acres of potentially 

contaminated properties across the United States that are tracked by EPA that could be 

assessed for RE, energy efficiency, conservation, and innovative applications.

1

NAVSTA Newport, established during the Civil War era, encompasses about 1,063 acres 

stretching 6–7 miles along the western shore of Aquidneck Island in the towns of 

Portsmouth, Rhode Island, and Middletown, Rhode Island, and the city of Newport,

Rhode Island. The base footprint also includes the northern third of Gould Island in the 

town of Jamestown, Rhode Island. 

In 

addition, there are many other environmentally contaminated or impaired lands, mine 

sites, and mine-scarred lands under state enforcement. Furthermore, there may be 

opportunities to evaluate the feasibility for more sustainable cleanup practices, such as 

installing RE technologies to power cleanup systems. These systems can be included in 

plans for cleanup and longer-term land management activities using renewable or lowcarbon fuels to power equipment and create more efficient new and existing cleanup 

systems. 

EPA has been involved with NAVSTA Newport because there are multiple contaminated 

areas within the base that pose a threat to human health and the environment. The base

was designated a superfund site on the National Priorities List in 1989.

NAVSTA Newport is committed to working toward reducing the base’s dependency on

fossil fuels, decreasing its carbon footprint, and implementing RE projects where 

feasible. EPA Region 1 and NAVSTA Newport have engaged NREL to investigate the 

RE options for the base.

 1 U.S. Environmental Protection Agency (EPA). “RE-Powering America’s Land: Siting Renewable Energy on 

Potentially Contaminated Land and Mine Sites.”

http://www.epa.gov/renewableenergyland/docs/repower_mapping_tools.pdf. Accessed October 27, 2011.
2

2 Background

EPA has long been interested in incorporating RE technologies to reduce energy costs 

and carbon emissions at EPA-tracked sites and in returning brownfields and superfund 

sites into productive use. RE technologies have historically presented more expensive 

options; however, recent advances have lowered upfront costs and increased performance

of several RE technologies. EPA would like to enable property managers at contaminated 

sites to deploy the options that are cost effective. RE-Powering America’s Land’s

objective is to promote the use of RE in the energy mix at contaminated sites. 

Additionally, there are significant financial incentives offered by utilities and state and 

federal governments encouraging site owners to consider incorporating RE technologies 

to their sites to offset purchased electricity or sell into the commercial electricity grid. 

Federal legislation and mandates provide impetus for many federal entities, such as 

NAVSTA Newport, to take action. These include:

• The Energy Policy Act of 2005 (EPAct 2005) directs federal agencies to 

implement RE projects to reach specific RE goals. Section 203 of EPAct 2005 

states that federal agencies cannot have less than 7.5% of their electricity 

consumption come from RE sources in fiscal year (FY) 2013 and thereafter.

An important provision to note from this legislation is that federal agencies 

can receive double credit toward this goal for RE produced on site or on 

federal land and used at a federal facility.2

• Executive Order 13423 mandates that 50% of statutorily required RE comes 

from “new” sources since 1999.3

• Executive Order 13514 mandates targets for the reduction of greenhouse gases

(GHGs) using various methods including increased use of RE from on-site 

projects.4

As an illustrative example, the task in front of many entities, such as NAVSTA Newport, 

is to determine whether it is more beneficial to install a 5,000 ft2 solar hot water system

with no incentive and a 12-year simple payback; a 25 kW PV system with a 30% rebate 

incentive and a 29-year simple payback; or a 1.5 MW wind turbine with a production 

incentive for third-party ownership that provides the owner with a $0.021/kWh tax credit

for the first 10 years of operation. 

This example illuminates some of the difficulties of evaluating the different RE 

technologies: they have different operating parameters and costs, they will be installed at 

locations with different RE resources, they will displace different energy types with 

different competing costs of energy, they will qualify for different incentives, and they 

 2 Public Law 109-58, 109th Congress. “Energy Policy Act of 2005.” http://doi.net/iepa/EnergyPolicyActof2005.pdf.

Accessed September 30, 2011. 3 U.S. EPA. “Executive Order 13423.” http://www.epa.gov/greeningepa/practices/eo13423.htm. Accessed September 

30, 2011. 4 Federal Register. “Executive Order 13514.” http://edocket.access.gpo.gov/2009/pdf/E9-24518.pdf. Accessed 

September 30, 2011. 
3

will meet different objectives. There is no “one-size-fits-all” RE solution. Guiding the 

most effective allocation of project funds requires a complex analysis that considers all or 

most of these factors.

This report used the building energy load and cost data provided by NAVSTA Newport 

to derive the optimal mix of technologies and system sizes that yields lowest life cycle 

cost (LCC), which serves to maximize return on investment (ROI). These derived RE 

solutions considered multiple technologies in the energy mix and their relative 

contributions after iteratively re-sizing and re-optimizing the RE system sizes. The 

renewable energy optimization (REO) analysis estimates the size, LCCs, savings, rate of 

return, and simple payback period for each technology at the largest building locations to 

come up with an RE solution representing the optimal mix of technologies at NAVSTA 

Newport. This report identifies an RE “solutions case” that provides real savings over 

continuing business as usual case, or “base case,” of energy use over the next 25 years.

Based on site, energy, and cost data provided by NAVSTA Newport, NREL conducted 

an optimization-based screening analysis of RE technologies for NAVSTA Newport. 

The objective of this analysis is to identify the economic feasibility of renewable 

technologies that could be considered at this site as it moves toward net-zero energy. 

Federal mandates for more RE in the energy mix used by federal agencies, coupled with 

financial incentives offered by utilities and state and federal governments, galvanize 

NAVSTA Newport to consider adding RE technologies to provide cost-effective 

electricity to the base. This study is a first-level screening intended to help NAVSTA 

Newport establish clear priorities in pursuing RE technologies. Additional analysis,

including more detailed performance modeling and a building-specific (or site-specific 

for biomass, wind, tidal, or geothermal) assessment, is required prior to implementation 

of any technologies recommended in this report. 

2.1 Study Objectives

The overall objective of this report is to provide energy, public works, buildings, and 

planning department personnel with objective information regarding multiple RE

technology options for reducing the base-wide consumption of fossil-fuel-sourced 

electricity. REO allows for the designation of a screening criterion, and for this analysis,

the REO screening criterion used was the ROI considering the LCCs over a 25-year 

project life to determine effective RE solutions and calculate the rate of return through a 

complex, multi-step analysis. The results of the analyses identify the best opportunities

for cost-effective implementation of RE technologies at NAVSTA Newport. 

2.2 Scope of Study

The analysis combines NAVSTA Newport site data with information from NREL's RE 

resource databases5; other databases from Platts, Inc. (avoided cost or wholesale electric 

power cost)6; and the Database of State Incentives for Renewable Energy (DSIRE)

7

 5 NREL. Geographical Information System (GIS) database of renewable energy resource information.

to 

http://www.nrel.gov/gis/. Accessed May 2010. 6 Platts, http://www.platts.com/Home.aspx. Accessed May 2010.
4

estimate the installed cost (including the effects of incentives and tax depreciation), 

energy performance, cost savings, and LCC effectiveness of RE technologies. 

EPA and NREL agreed to assess the following RE technologies using REO for this phase 

of the study:

• Daylighting

• Wind power

• Solar ventilation supply air preheating

• Biomass energy

• Solar water heating

• Photovoltaics (PV)

• Solar industrial process heat

NAVSTA Newport requested that additional RE technologies be investigated, such as 

biofuels from algae, tidal power, and GSHPs. These technologies were considered, and 

the findings are outlined in the report, but they were not analyzed with the REO tool as 

the modeling parameters are too broad (e.g., extent of resource and costing) to do 

meaningful analysis as done for the other technologies that have more established sizing 

algorithms and more consistent costing parameters. For example, without some sitespecific resource information obtained by drilling test bore holes and completing a soil 

profile, it is not possible to obtain a reasonable estimate for a GSHP as the soil 

characteristics are a key variable for determining system size.

The wind resource data, collected at Coddington Point and Tank Farm #4, was used for a 

separate analysis of 9 MW utility-scale wind turbines at the site. These results were 

added into the REO analysis and are shown in detail in Appendix A.

Consistent with rates published by the National Institute of Standards and Technology 

(NIST) for federal analysis, NREL used a discount rate of 4.6% to represent the timevalue of money. Other parameters used in the economic analysis (e.g., fuel escalation rate 

and general inflation rate) are based on the same publication: Energy Price Indices and 

Discount Factors for Life-Cycle Cost Analysis.

8

 7 DSIRE. North Carolina State University.

NREL completed the analysis with and 

without tax-based incentives (tax credits) to provide guidance for the impact of the tax 

credits on technology viability. NREL assumed a typical corporate tax liability structure 

in the 35% tax bracket for estimating the effects of the business investment tax credit

(ITC) and accelerated depreciation for scenarios when a third-party operator, financer, 

investor, or owner was considered.

www.dsireusa.org. Accessed May 2010. 8 DOE. Energy Price Indices and Discount Factors for Life-Cycle Cost Analysis, Annual Supplement to Handbook 135

(ASHB 135), http://www1.eere.energy.gov/femp/information/download_blcc.html. Accessed May 2010.
5

3 Technology Characterizations

EPA and NREL assessed the RE technologies using REO for this study. Initial cost, 

efficiency, and operation and maintenance (O&M) cost for each of the RE technologies 

are characterized according to the cost and performance data reported in the Power 

Technologies Energy Data Book9 and in Renewable Energy Technology 

Characterizations.

10

Each of the technologies is characterized briefly in this section. Resource and technology 

details can be found in Appendices A–E.

Other RE technologies were also examined, including biofuels from 

algae, tidal power, and geothermal energy. The characteristic cost and performance data 

from several sources are detailed in this report. 

3.1 Daylighting

The term “daylighting” refers to consciously adding natural light to buildings to reduce 

the need for artificial light. A complete daylighting system consists of apertures 

(skylights, light shelves, and windows) to admit and distribute sunlight and a controller to 

modulate artificial light as needed to maintain the desired level of light for the building 

space. Electricity for lighting is reduced and no scheduled maintenance is required; 

however, skylights may increase roof maintenance. Figure 1 is a photograph of skylights 

in an application similar to the configuration modeled for this study. Daylighting was 

considered in the office and warehouse buildings of NAVSTA Newport. Utilization of 

daylighting can enhance both the quality of light and comfort for the people working in 

these buildings. It can also contribute to lowering overall cooling loads by reducing waste 

or by-product heat from electric lighting.

Figure 1. Daylighting in Hawaii

Photo by Scott Bly, NREL/PIX 07626

 9 NREL. Power Technologies Energy Data Book, Edition Four. http://www.nrel.gov/analysis/power_databook/. 

Accessed May 2010.

10 DOE. Renewable Energy Technology Characterizations. EPRI Topical Report No. TR-109496.

http://www1.eere.energy.gov/ba/pba/tech_characterizations.html. Accessed May 2010.
6

Table 1 lists the characteristics of daylighting technology used in this analysis.

Daylighting was considered only in the office, utility, and warehouse spaces at NAVSTA 

Newport. 

Table 1. Characteristics of Daylighting Technology

Lighting Levels

Office 30 Fc

Warehouse 15 Fc

Utility 30 Fc

Skylight Transmittance Coefficient 0.7

Lightwell Transmittance Coefficient 0.8

Utilization Daylight Coefficient 0.55

Utilization Electric Light Coefficient 0.55

Luminous Efficacy Electric Light 75 Lumens/W

Roof U-value 0.1 Btu/hr/F

Skylight U-value 0.5 Btu/hr/F

Cooling Coefficient of Performance (COP) 3.5

Heating Efficiency Coefficient 0.8

Skylight Cost $25/ft2

Controls Cost $0.25/ft2 floor area

3.2 Wind Power

Uneven heating of the earth’s surface creates wind energy. Variation in heating and 

factors such as surface orientation or slope, rate of reflectivity, absorptivity, and 

transmissivity also affect the wind resource. In addition, the wind resource can be 

affected (accelerated, decelerated, or made turbulent) by factors such as terrain, bodies of 

water, buildings, and vegetative cover. Wind power and energy and the results of the 

wind assessment are discussed in detail in Appendix A. 

Wind is air with high kinetic energy that can be transformed into useful work via wind 

turbine blades and a generator. Overall, wind is a diffuse resource that can generate 

electricity cost effectively and competitively in regions with a good wind resource, high 

cost of electricity, or both.

3.2.1 Wind Characteristics

Winds vary with the season, time of day, and weather events. Analysis of wind data 

focuses on several critical aspects of the data—average annual wind speed, frequency 

distribution of the wind at various speeds, turbulence, vertical wind shear, and maximum 

gusts. 
7

The wind speed at any given time determines the amount of power available in the wind.

The power available in the wind is given by:

P = 1⁄2 * A * ρ * V3

where

P = power of the wind [W]

A = windswept area of the rotor (blades) [m2

] = πD2/4 = πr

2

ρ = density of the air [kg/m3

] (at sea level at 15°C)

V = velocity of the wind [m/s]

As shown, wind power is proportional to velocity cubed (V3

). This matters because if 

wind velocity is doubled, wind power increases by a factor of eight (23 = 8). 

Consequently, a small difference (e.g., increase) in average speed causes significant 

differences (e.g., increases) in energy production. Examining ways to increase the wind 

velocity at a particular site should be considered. Normally, the easiest way to 

accomplish this is to increase the height of the tower. The wind industry has been moving 

toward higher towers, and the industry norm has increased from 30 m to 80 m over the 

last 15–20 years. 

The map of the national wind resource can be seen in Figure 2. Wind maps can give a 

visual approximation of the wind resource in an area but do not provide enough data for 

estimating annual electricity output at a particular site. On-site wind data collected for a 

period of 1–3 years is necessary to estimate wind turbine performance. This study used 

recently collected on-site wind data for its screening level production estimates and 

analysis.
8

Figure 2. Map of U.S. wind resources

Credit: NREL, Wind Powering America

3.2.2 Wind Turbines

Wind turbines consist of rotating blades that convert the momentum of the wind to 

electric power. They have a number of moving parts and require regularly scheduled and 

unscheduled maintenance. Manufacturer warranties cover the first 2–5 years. 

Professional wind turbine maintenance contractors (aka windsmiths) are recommended 

after the warranty period. Figure 3 shows large wind turbines that may be considered for 

NAVSTA Newport. 

Figure 3. Modern wind turbines

Photo by STG Inc., NREL/PIX 16797
9

Wind turbines, at less than wind farm scale, are typically cost effective where the average 

wind speed is high, where the competing energy costs are high, or a combination of both. 

Large wind farms of 100–500 MW have been driving the industry because of lower 

installed costs due largely to economies of scale and improved low wind speed turbine 

technology, which result in an overall lower cost of energy. No more than about 10 wind 

turbines would be considered for NAVSTA Newport due to land, permitting, and 

neighbor constraints. The small number of turbines and challenging construction sites 

would result in significantly higher installed costs than the wind farm industry norms. 

In the United States, there have been about 35,600 MW of wind power installed with

over 10,000 MW installed in 2009.11 Turbines are available from as small as 250 W to as 

large as 5 MW. For the size of the wind plants considered here, large turbines in the 

range of 800 kW to 3,000 kW per turbine would be the optimal size. A 15 MW plant 

could consist of ten 1.5 MW turbines.

Table 2 lists the characteristics of wind technology typically used in REO analyses and 

shows the relation of cost to project size.

Table 2. Characteristics of Wind Power Technology

Tower Height 80 m

Wind Shear Exponent 0.115

Acres per MW 40–60 Ac/MW (for wind farms)

Capacity Factor 35%

Capital Cost $2,200/kW 

O&M Cost $7.90/yr/kW

Power/Area 0.46 kW/m2

 11 Wiser, R.; Bollinger, M. 2009 Wind Technologies Market Report. Washington, D.C.: Department of Energy. 

http://www1.eere.energy.gov/windandhydro/pdfs/2009_wind_technologies_market_report.pdf. Accessed April 2011.
10

3.3 The Solar Resource

The solar resource available outside the earth’s atmosphere is immense and always 

available. The solar radiation that gets filtered through the atmosphere with its 

accompanying clouds, moisture, and pollution is still enormous, though availability 

follows daily and seasonal patterns occasionally interrupted by weather events. The 

challenge in working with the solar resource for electricity generating applications is that 

the resource is relatively diffuse and unconcentrated. 

For making electricity, only bands of the solar spectrum within the visible light 

wavelengths are utilized, and the objective for PV manufacturers is to utilize as much of 

that available energy as possible. For heating applications, whether for space (air) or 

materials (mass), the light energy is transformed into heat energy as it strikes a surface 

and is absorbed. 

In the continental United States, the intensity of solar radiation during the middle 6–8 

hours of the day is usually in the 500–1,000 W/m2 range. A daily pattern of insolation 

intensity can be seen in Figure 4. 

To facilitate climate comparison and predict system performance, the amount of solar 

radiation that falls on a collector throughout the day has been integrated to determine the 

area under the curve. The conventional level of intensity is 1,000 W/m2 (1 kW/m2

),

termed peak sun-hours. The solar resource at a site is often reported in sun-hours/day, 

which equates to kilowatt-hours per square meter per day. There have been extensive 

weather data collection efforts throughout the United States for a number of years and 

with a wide variety of data collectors, end users, and end uses in mind.

Figure 4. Annual daily insolation pattern integrated into a yearly average of sun hours per 

day

Illustration by Ameco Solar, Inc.
11

An important characteristic of the solar resource is determining what portion of the 

insolation is “direct” versus “diffuse” or “indirect.” Direct normal is the term used to 

describe solar insolation (aka radiation) coming in perpendicular to the surface in 

question—normally either a horizontal surface or one tilted at the latitude angle. Diffuse 

insolation is that scattered by clouds, moisture, or dust in the atmosphere. 

Figure 5. Atmospheric impacts on diffuse and direct beam insolation

The solar radiation resource data that was selected for resource analysis for NAVSTA 

Newport with particular solar technology applications in mind were chosen for four 

primary application purposes:

1. Solar hot water or PV systems that are most commonly operated at a fixed-tilt 

angle that corresponds to the local latitude

2. Transpired solar collectors that are most commonly added onto or affixed in front 

of vertical south-facing exterior walls

3. Horizontal roof-mounted PV systems that have gained popularity due to relative 

simple installation

4. Concentrated solar systems with single-axis tracking.

An advantage of solar compared to other renewable resources is that the variation of the 

solar resource from best-to-worst locations across the United States varies by roughly a 

factor of 2.4 to 1. This means that a solar project can be done essentially anywhere, 

though 2.4 times as many square meters (or feet) of PV or solar collector might be 

needed for a location with a low solar resource versus a location with a high solar 

resource. The key parameters for determining cost-effective applications will be highly 

influenced by other site-specific factors beyond solar resource alone such as incentives or 

construction labor rates. 
12

3.4 Solar Ventilation Air Preheat

SVP is a very simple yet effective technology. SVP systems use the sun’s heat to warm 

air before it is brought into a building’s heating, ventilation, and air-conditioning 

(HVAC) system. Adding inexpensive hot air generated on cold sunny days to the supply 

air of an HVAC system can lower heating bills. 

The system operates by the sun heating special siding (a metal sheathing perforated with 

small holes also known as a transpired solar collector or solar wall) that covers a portion 

of the south-facing exterior wall of a building. The sheathing leaves an 8–10 cm plenum 

between its outer surface and the building wall as shown in Figure 6 below. The 

sheathing has holes about 1 mm in diameter and about 9 mm apart to allow for effective 

collection of the heated air. The metal sheathing is usually painted black or another dark, 

light-absorbing color. The perimeter is sealed with flashing. 

Solar radiation heats the metal sheathing and the air immediately adjacent to it (a thin 

film of air known as the boundary layer). The heated boundary layer air is drawn by a fan

into the plenum through the small holes before it can mix with the ambient air. The 

warmed air is added to and mixed with ventilation air going into the building by the fan.

This technology is only for preheating ventilation air; there is no recirculation to the inlet 

for reheating. For summer conditions when heated air is not needed in the building, a

bypass damper on the face of the wall admits fresh outside air with no additional heating.

SVP systems are very low maintenance as there is only one moving part, the fan. Savings 

at each site depend on the solar resource, collector orientation, and the heating degree 

days for that site. Figure 6 illustrates how an SVP system works.

Figure 6. SVP system schematic

Illustration by Conserval Engineering, Inc.
13

SVP is generally cost effective in more northern latitudes that can use the heat throughout

much of the year. A site with a heating season of four months or longer could consider 

this technology. An SVP system at the U.S. Bureau of Reclamation water treatment

facility in Leadville, Colorado (Figure 7), cost $28,000 and saves $4,000 per year.12

Figure 7. SVP system in Leadville, Colorado

Photo by Thomas Bunelle, NREL/PIX 08357

Figure 8 shows the energy savings associated with utilizing SVP systems based on the 

distribution of solar resource across the country.

Figure 8. Map of SVP delivery (depending on both solar and heating requirements)

Due to the low cost of this simple technology (about $20/ft2 installed) and its high 

efficiency, over 2 million ft2 have been installed worldwide,

13

 12 Walker, A. “Solar Air Heating.” Presented at the Implementing Renewable Energy Projects Workshop, Washington 

DC, October 11-12, 2005.

mostly in manufacturing 

13 Conserval, Inc. http://solarwall.com/en/home.php. Accessed October 20, 2011.
14

plants in the Northeast and Canada. Buildings such as high bay automotive shops (due to 

the need for high ventilation rates) are very good candidates for SVP systems.

The size of an SVP system is determined by the optimization, but there are some 

constraints, as noted in Appendix B. 

Table 3 lists the initial and annual costs associated with SVP technology characterization. 

Table 4 lists the ventilation rates required for each type of space at NAVSTA Newport. 

Often the size is limited by the available south wall area, which was estimated from the 

NAVSTA Newport data provided.

Table 3. Initial Cost of Components of SVP Technology

Material Cost $14/ft2

Installation Cost $14/ft2

Ductwork $4/ft2

Other $4/ft2

Total Installed Cost $36/ft2

O&M Cost $0

Table 4. Ventilation Rates Used in the Analysis14

Warehouse Office Lab Residence Other

Ventilation Rate (cfm/ft2) 0.02 0.14 1.00 0.00 0.34

 14 ANSI/ASHRAE. Standard 62.1-2007. Ventilation for Acceptable Indoor Air Quality. Atlanta, GA: American Society 

of Heating, Refrigerating, and Air-Conditioning Engineers. www.ashrae.org/pressroom/detail/16298. Accessed May 

2009
15

3.5 Solar Water Heating

Solar water heating systems use the sun to heat water that is stored in tanks for later use. 

Solar collectors provide the heat, heat exchangers heat potable water, and pumps circulate 

the fluid. Such systems also contain expansion tanks, pressure relief valves, flush and fill 

valves, and controls. Typical solar water heating systems, as shown in Figure Error! 

Reference source not found.9, are sized to provide 40%–70% of water heating 

requirements. The conventional water heating system is used as a back-up to the solar 

system.

Figure 9. Solar hot water heating system schematic

Illustration by Jim Leyshon, NREL

A roof-mounted solar hot water system designed to meet the hot water load for showers 

and laundry at the Chickasaw National Recreation Area in Oklahoma can be seen in 

Figure 10.

Figure 10. Solar water heating system at Chickasaw National Recreation Area, Oklahoma

Photo by Andy Walker, NREL
16

There are three types of solar water heating collectors: unglazed plastic collectors for low 

temperature applications; glazed, insulated flat plate collectors for mid-temperature hot 

water; and evacuated tube collectors with reflectors for high temperature applications.

3.5.1 Unglazed Plastic Collectors for Low Temperature Applications

Typical solar water heating systems provide 40%–70% of water-heating requirements. 

Typical solar pool-heating systems use unglazed polymer collectors that provide 50%–

100% of swimming pool heating requirements. The low temperature requirements of 

swimming pools enable the systems to meet a high fraction of the load. Typical systems 

generate 1,600 therms, or 46,000 kWh, of energy per year and cost $0.30–$0.50/W (of 

peak capacity). 

3.5.2 Glazed, Insulated Flat Plate Collectors for Mid-Temperature Hot 

Water

Typical flat plate collectors deliver about 900 kWh/m2

/yr and cost $1–$2/W, or 

$0.08/kWh. The system delivers heat (Btus), not electricity. The units were converted to 

electrical units for comparative purposes only. The energy costs of solar thermal systems 

have declined by more than 50% due to technology improvements. 

3.5.3 Evacuated Tube Collectors with Reflectors for High Temperature 

Applications

Parabolic trough collectors with evacuated tubes cost about $1/W and deliver about 900 

kWh/m2/yr.15

Water heating load (gallons per day) is estimated according to the statistics available16

Table 5. Water Heating Load and Characteristics

and is listed in Table 5. System sizing equations can be found in Appendix C.

Hot Water as a Fraction of Total Building Energy

Office 0.089506

Education 0.219420

Healthcare 0.262063

Lodging 0.403771

Public Assembly 0.153914

Food Service 0.112016

 15 For a full listing of certified systems, please visit the Florida Solar Energy Center at 

http://www.fsec.ucf.edu/en/certification-testing/STsystems/ratings/index.htm#DHWRatings. 16 DOE Office of Building Technologies. “2008 Building Energy Databook.” http://buildingsdatabook.eren.doe.gov/. 

Accessed May 2010.
17

Food Sales 0.042623

Warehouse 0.052219

Other 0.088850

Average of All 0.152486

Solar Domestic 

Water Heater 

(SDWH) Efficiency

0.4

System Cost per 

Square Foot of 

Collector

$73/ft2

O&M Cost 0.005% of initial cost

Auxiliary Efficiency 0.8

Source: DOE/OBT Energy Databook17

3.6 Photovoltaics

PVs are panels that convert sunlight directly into electricity. Fixed-axis PV has no 

moving parts and little required maintenance, make no noise, and emit no pollution (see 

Figure 11). Solar cells are fabricated from thin semi-conductor wafers with an electric 

field applied to the cell to make one side positive and one side negative. When the sun’s 

light strikes the solar cell, electrons are knocked loose from one side of the wafer and are 

conducted from one side of the solar cell to the other with an embedded conductor wire. 

This movement of electrons along the conductor wire is an electric current, or electricity, 

which is collected and used to power any electrical device.

Figure 11. Solar electric PV system

Photo by Jamie Keller, NREL/PIX 19697

 17 DOE Office of Building Technologies. “2008 Building Energy Databook.” http://buildingsdatabook.eren.doe.gov/. 

Accessed May 2010.
18

Over the past two decades, significant improvements have been made in the efficiency of 

PV materials, and manufacturing costs have been driven down, yet PV is still more 

expensive than conventional grid electricity, and, in the United States, PV’s cost 

effectiveness is dependent to a large degree on the local, state, or utility incentive 

programs coupled with tax-based incentives. 

The cost of PV-generated electricity has dropped 15- to 20-fold in the last 40 years, and 

grid-connected PV systems currently sell for about $5–$8/Wp (peak Watt), resulting in 

energy produced in the $0.20–$0.32/kWh range, including support structures and power 

conditioning equipment. Complete system cost is reported at $8,500/kW.

18

The PV cost function used in the analysis can be seen in Appendix D. Though the “Initial 

Cost” shown in Table 6 is at $8,500/kW, it should be noted that this price is for very 

small systems. For an optimization analysis range of approximately 100–10,000 kW, the 

installed cost range is $4,300–$5,000/kW. In this analysis, we represent cost as a function 

of size as $6.7637 multiplied by the system size in kilowatts raised to an exponent of –

0.0615. O&M costs are reported at $0.006/kWh as produced in Factors Associated with 

Photovoltaic System Costs.

PV modules 

themselves are highly reliable and last 20 years or longer.

19

Figure 12. PV system schematic

Illustration by Jim Leyshon, NREL

 18 RS Means Green Building Project Planning and Cost Estimating, 2010.

http://www.rsmeans.com/bookstore/detail.asp?sku=67338A, Accessed March 2011. 19 Mortensen, J. Factors Associated with Photovoltaic System Costs. NREL/TP-620-29649. Golden, CO: NREL, June 

2001.
19

About 79 MW of PV were installed in the United States in 2000, and 878 MW of PV 

were installed in 2010, indicating the growth of this industry.20 Annual market growth for 

PV has been about 25% as a result of reduced prices, government incentives, and 

successful global marketing. A growth rate of over 100% due to the ITC made available 

through the Treasury Cash Grant program occurred in 2010.

21 There is concern that when 

this program expires (December 2011) there will be a significant impact on the PV 

market and prices. Current leading PV companies in the United States total 104 MW of 

rated power production manufactured per year.22

Hundreds of applications are cost effective for off-grid needs. Viability of on-grid PV can 

be determined by the level of incentives, the solar resource, and the competing cost of 

electricity. However, the fastest growing market segment is currently grid-connected PV, 

such as roof-mounted arrays on homes and commercial buildings in the United States. 

California is subsidizing PV systems because it is considered cost effective to reduce 

their dependence on natural gas, especially for peak daytime loads for air conditioning, 

which matches PV output.

Almost two-thirds of U.S.-manufactured 

PV is exported.

23

The solar resource across the country can be seen in Figure 13. The results shown are for 

a flat plate collector tilted at the latitude angle.

Figure 13. Solar resource across the United States

 20 SEIA. “U.S. Solar Market InsightTM, 2010 Year in Review, Executive Summary.”

http://www.seia.org/galleries/pdf/SMI-YIR-2010-ES.pdf. Accessed March 2011. 21 SEIA. “U.S. Solar Market Insight, 2010 Year in Review, Executive Summary.” 

http://www.seia.org/galleries/pdf/SMI-YIR-2010-ES.pdf. Accessed March 2011. 22 PG&E. “SGIP - Available Funding and Program Statistics.”

http://www.pge.com/mybusiness/energysavingsrebates/selfgenerationincentive/availablefundingandprogramstatistics.s

html. Accessed May 2009. 23 DOE. Renewable Energy Technology Characterizations. EPRI Topical Report No. TR-109496.

http://www1.eere.energy.gov/ba/pba/tech_characterizations.html. Accessed May 2010.
20

PV system sizing details can be found in Appendix D. Key sizing and cost variables are 

listed in Table 6.

Table 6. Characteristics of PV Technology

Source Characteristic Metric

Initial Cost $8,500/kW RS Means Green Building Project Planning and Cost Estimating, 

2010; NREL Data from Project Bids

O&M Cost $0.006/kWh Renewable Energy Technology Characterizations, EPRI TR109496, 1997.C185

Balance-of-System

Efficiency 0.77 PVWatts documentation www.nrel.gov

Acres per MW 6.5 Ac/MW

3.7 Solar Industrial Process Heat and Solar Thermal Electric

Solar industrial process heat systems have parabolic trough solar collectors that focus the 

sun’s rays onto a pipe running through a glass cover pipe down the focal line of the 

trough. Motors and controls track the sun for maximum gain from east to west in a northsouth oriented trough. The concentrating collectors require direct sun with minimal 

clouds, moisture, or dust. The desert southwest, which has many clear sunny days every 

year, is considered the most viable region for these concentrating systems.

A key parameter in establishing the extent of the suitability of the solar resource for a 

concentrating system is the “clearness index” (aka clear sky insolation clearness index). 

The clearness index, often denoted by KT, is the ratio of the horizontal radiation incident 

on a surface on the ground relative to the radiation incident on a surface in space with no 

atmospheric attenuation, clouds, pollution, rain, or volcanic ash. It describes the fraction 

of the insolation just outside the atmosphere that actually reaches the surface of the earth.

The annual clearness index, KT, for Providence, Rhode Island, is 0.50.

24 In Tucumcari, 

New Mexico, it is 0.62,

25

Since the system has moving parts, it requires preventative and unscheduled 

maintenance. Figure 14 shows a solar thermal system of the size and type considered for 

NAVSTA Newport. In order to displace natural gas (to get to net zero), on-site thermal 

storage is required. Additional equipment to consider with a thermal storage system may 

include a fluid tank, tubes in sand, or tubes in concrete.

representing a 24% increase in “clearness” of the atmosphere. 

The increased clearness in the atmospheric conditions in Tucumcari makes it a better 

candidate for concentrating solar collectors than Providence.

 24The Solar Radiation Data Manual for Buildings, NREL. http://rredc.nrel.gov/solar/old_data/nsrdb/1961-

1990/bluebook/data/14765.SBF. Accessed September 30, 2011. 25The Solar Radiation Data Manual for Buildings, NREL. http://rredc.nrel.gov/solar/old_data/nsrdb/1961-

1990/bluebook/data/23048.SBF. Accessed September 30, 2011.
21

Figure 14. Solar industrial process heat system

Photo by Ed Hancock, NREL

Table 7. Characteristics of Solar Industrial Process Heat Technology

Characteristic Metric

Solar Thermal Cost $60/ft2

O&M Cost $0.127/therm/yr

Coefficient of Efficiency 0.33

Cost of Thermal Storage $1,465/therm

Hours Per Day of Solar Collection 6 hrs/day

Cogen Cost $1,650/kW

Cogen Efficiency 0.2

Boiler Capacity Factor 0.85

Coefficient of Heat Exchanger 

Effectiveness 0.7

Federal Production Tax Credit $0.01/kWh

Energy savings consist of savings in natural gas and electricity. Natural gas savings are 

limited to the minimum of: 

1. Base case natural gas use 

2. RE heat generating capacity. 

Electric savings are limited to the minimum of electric peak, then RE generation above 

that is treated as wholesale power to the utility. Electric savings are limited to: 

1. The minimum cogeneration size (kW) 

2. Heat generating capacity of the plant times heat-to-electric cogeneration 

efficiency. 
22

Thermal energy as a by-product of electric generation is added back into the gas savings 

but multiplied by a heat exchanger effectiveness. System sizing equations can be found in 

Appendix E. 

3.8 Biomass Energy

Biomass energy is fuel, heat, or electricity produced from organic materials such as 

plants, agricultural residues, forestry by-products, and municipal or industrial wastes. 

Biomass has its energy stored within the chemical structure of the organic substance 

itself. Solid or liquid biomass feedstocks from surrounding areas can be acquired, 

sometimes at low cost, and converted to heat or electricity for buildings. Much of the 

plant-based biomass resource is already in a form that is readily transportable and 

dispatchable, with no energy transformation necessary; although ensuring the fuel has the 

required moisture content is often critical. There are costs associated with moisture 

removal/regulation, storage, and transport. Maintaining the energy quality (i.e., moisture 

content) of the fuel may require some environmental control and consideration for a shelf 

life that is not indefinite.

This analysis considered several available technologies to convert biomass feedstocks 

into heat and electricity. These include direct combustion, gasification, and liquefaction 

of solid biomass and anaerobic digestion of liquid biomass. 

Combustion of solid biomass can be used to generate steam or used in a topping cycle for 

steam cogeneration of heat and power at a facility. For the latter, some of the heat output 

of the boiler may be converted to electricity by a steam turbine in a cogeneration topping 

cycle. Combustion of dry biomass feedstocks, such as wood mill waste available in the 

area, was also analyzed. Dry sources of waste from the NAVSTA Newport site may also 

be considered if the site were to include an inventory of waste streams, such as waste 

pallets or tree trimmings. Given the level of vegetation viewed across the base during the 

site visit, the site is not considered a sustainable source of vegetative biomass. Further 

investigation of the waste stream is needed to determine if there is enough daily waste 

generated to be viable.

Gasification of solid biomass produces a fuel gas by heating the feed material in a vessel, 

sometimes with the additional oxygen and/or water (Figure 15). The fuel gas, aka syngas, 

can be used directly in combustion for a boiler or stored for dispatchable use.

In wet feedstocks, decomposition reactions take place that produce a mixture of hydrogen 

and carbon monoxide, along with water, methane, and carbon dioxide. Anaerobic 

digestion of wet feedstocks is considered in this analysis to produce methane gas. Wet 

waste streams include confined animal waste from surrounding areas. 

Unlike the other RE technologies considered in this report, on-site use of biomass 

resources involves atmospheric emissions, solid waste residues (ash), and possible waterborne wastes. It may be expected, however, that emissions from a gasification operation 

would be no worse than those of a direct-burn operation.
23

Figure 15. Biomass-fueled gasifier and boiler

Photo by Bob Bender, NREL/PIX 13534

Figure 16. Biomass resources in the United States by tonnage
24

3.8.1 Biomass Resource Data 

Biomass fuel resources available at NAVSTA Newport were taken from existing 

databases. No on-site biomass data was provided. Biomass resources considered are 

detailed in Appendix F. Figure 16 provides a visual context for the biomass resources 

available across the country on a county-by-county basis. 

3.8.2 Technology Characteristics of Biomass Energy Conversion 

Configurations

The emerging biomass energy sector is focusing on increasing the conversion efficiency 

of solid biomass-based fuels compared to the standard boiler and steam-cycle 

configuration. While further research and development (R&D) is needed to increase 

reliability, reduce maintenance costs, and reduce capital costs, these new biomass 

conversion approaches are already penetrating the biomass energy sector in a number of 

countries. The details of these conversion technologies and system configurations can be 

found in Appendix F.

3.9 Biofuels from Algae

NAVSTA Newport requested an investigation of the potential for using their existing 

tanks on various tank farms for the production of biofuels processed using algae. 

Conventional U.S.-based liquid biofuel production, primarily corn-grain ethanol and 

soybean biodiesel, have been in use for a number of years. There are known impacts 

regarding GHGs, use of fertilizers, water consumption, and fossil fuels used for 

production and transport. The production of biofuels from algae is a relatively new area 

in the fuel development field. Experiments in the laboratory have yielded results that 

merit further investigation. 

Advantages of this type of microalgae production include the ability to utilize nutrientladen wastewater streams reducing or negating the need for fertilizers and the higher 

yields per land than conventional soybean production. However, some studies have 

suggested that harvesting microalgae is energy intensive and may require significant 

chemical inputs to achieve effective separation.26

Overall, biofuels from algae are viewed as having a reasonable potential as a fuel supply, 

but it is dependent upon several independent factors such as continued technology 

development, energy and environmental policy, and relative cost of competing fuels. 

Yields improve significantly with 

heterotrophic (i.e., sugar-grown) algae.

To help frame potential yields, an estimate from an NREL biologist, Dr. Al Darzins, for a 

moderately producing sugar-grown algae (20 gm/m2/day) that has an oil content of 15% 

 26 Williams, P.R.D.; Inman, D.; Aden, A.; Heath, G.A. “Environmental and Sustainability Factors Associated With 

Next-Generation Biofuels in the U.S.: What Do We Really Know?” 

http://pubs.acs.org/doi/full/10.1021/es900250d?prevSearch=&searchHistoryKey=&cookieSet=1. Accessed May 31, 

2011.
25

can be expected to produce about 75–95 L/yr (about 20–25 gal/yr) of algal oil using a 93 

m

2 (about 1,000 ft2

) pond.27

Using this biofuel production range, based on estimated dimensions taken during the site 

visit, a single tank at NAVSTA Newport might have a diameter of approximately 30–45 

m (100–150 ft) with a resultant area of approximately 700–1,700 m2 (8,000–18,000 ft2). 

Using the production figures above, annual output from a single tank might be in the 

160–450 gal/yr range. Depending on the competing cost of fuel (roughly $3–$5/gal), the 

value of the biofuel that could be produced from a single tank would fall between $500/yr 

and $2,300/yr. There are not reliable estimates for the infrastructure costs to produce that 

level of annual economic value, but the likely development costs would dwarf the benefit 

range.

Regarding the technology itself and the production of oil, there are a host of issues still to 

be studied further, including feedstock optimization, fuel quality standardization, 

reduction of energy consumption for drying, waste stream disposal, overall sustainability, 

and net GHG displacement.

Transportation fuels generally have a higher value than heating or power generation fuels 

due to their high energy content and ease of transport. When algal fuels become more 

cost competitive and commercially available, it is likely that an initial (possibly primary) 

use will be for transportation. However, many aspects of this technology are still years to 

decades away from being commercial. 

In terms of NAVSTA Newport hosting a microalgae plant, there are many factors to 

evaluate. The technology is not considered a mature technology at this point. A project 

would require hiring staff dedicated to algae production (with algae and fermentation 

experience to start). There would need to be a dedicated fermentation facility with 

carefully monitored and controlled growing conditions—pH, temperature, dissolved 

oxygen, and mixtures, for example. There would also need to be a significant 

downstream infrastructure to harvest the cells, extract the oil, convert the oil to fuel, 

process residues, and monitor fermentation rates. Given these constraints, this sort of 

homegrown biofuel experiment at NAVSTA Newport is not likely to be cost effective.

3.10 Tidal Power

Tidal power was not included in the original REO analysis. NAVSTA Newport requested 

an investigation into the potential for utilizing marine-based hydro-generation (aka tidal 

power), so it was investigated separately. Given NAVSTA Newport’s location right on 

the Narragansett Bay, where tidal flows are seen every day, this RE resource is the most 

abundant, though not necessarily the most economic, renewable resource. 

Tidal power was one of the earliest forms of RE harnessed by mankind. The Spanish, 

French, and British built tidal storage ponds behind dams filled by incoming tides 

 27 Darzins, A. Email. NREL, Golden, CO, 4 June 2010.

Jarvis, E. Email. NREL, Golden, CO, 23 June 2010.
26

through sluice gates during rising tides.28 The trapped water was used to power a water 

wheel to mill grain. Tide mills were used in the United States and Great Britain in the 

17th–19th centuries for milling flour, sawing lumber, manufacturing paper and cotton, and 

grinding pepper and gunpowder.29

Tidal power has several advantages over other forms of RE but also has challenges in its 

availability and implementation. Though tidal power has been deployed successfully for 

mechanical power applications for centuries, the use of tidal currents for generating 

electricity is still a relatively new technology. Tidal power is non-polluting, reliable, and 

predictable. At a given location, the magnitude of the resource can be defined with 

reasonable certainty and the oscillations defined with precision. There are two primary 

factors of interest in the tide—the periodic volume of water available and the tidal current 

(or speed) of that water. Details of the resource and power conversion equations can be 

found in Appendix G.

This method relied on the use of “barrages” to capture 

the water at high tide. These gave way to steam-powered mills through the Industrial 

Revolution. The environmental impact of these barrages is high and, consequently, will 

not be considered further in this report.

The area of interest for tidal power for NAVSTA Newport is the channel between 

Conanicut and Aquidneck Islands. The channel varies in width between approximately 

0.5 and 2.5 miles near NAVSTA Newport, as shown in Figure 17. 

 28 Hagerman, G.; Polagye, B. “Methodology for Estimating Tidal Current Energy Resources and Power Production by 

Tidal In-Stream Energy Conversion (TISEC) Devices,” EPRI, 2006. 29 Elling Tide Mill. http://www.culture24.org.uk/am35881. Accessed September 2010.
27

Figure 17. Aquidneck Island in Narragansett Bay

Illustration by Paul Jordan, Rhode Island Department of Environmental Management

3.10.1 Tidal Power Technologies

Tidal current electricity conversion is still a relatively new technology. Ideas, approaches, 

energy capture, and generator designs are still being developed and tested. There are a 

number of turbine technologies that have been deployed and, similar to wind turbines of a 

couple generations ago, there are both vertical and horizontal axis turbines being 

investigated and developed. Over time, the most reliable turbines with reasonable energy 

conversion efficiencies will emerge. More experience in the field, with analyses of failure 

modes and documenting of O&M, are necessary to bring this industry to a more 

commercially mature stage.

Jurisdiction over the land underwater and NAVSTA Newport’s ability to place hydroturbines there is a new area of permitting to explore. Permits would be required from 

Tidal Flow

Aquidneck 

Island
28

Rhode Island Coastal Resource Management Council and the Rhode Island Department 

of Environmental Management.30

The tidal currents in the Narragansett Bay, as a whole, do not appear adequate at this time 

for cost-effective power generation with current technologies given the cost of competing 

electricity. However, there may be individual locations on the bay floor that have 

accelerated tidal current speeds and could merit further investigation with a bathymetric 

study. Increased tidal current speeds may prove viable. Over time, as conversion 

technologies improve, there could be technologies well-suited to the level of resource 

NAVSTA Newport has available. 

It is expected that it might take some time to receive 

the necessary permits, so beginning the process well in advance of an impending 

developable project is recommended.

Figure 18. Tidal power turbines

Photo by Marine Current Turbines Ltd.

3.11 Ground Source Heat Pumps

NAVSTA Newport requested an investigation into the potential for utilizing GSHP and 

geothermal heat pump (GHP) systems to provide heating and cooling to buildings using 

the earth’s thermal energy as both a thermal energy source and sink. 

In the United States alone, over 50,000 GSHP units are sold each year, with a majority of 

these for residential applications. It is estimated that a half million units are installed, 

 30 “Overview of Water Planning Authority in Rhode Island.” RI Water Resources Board. 

http://www.water.ri.gov/wapacmeetings/waterrights/regauthdiagrams.pdf. Accessed July 2011.
29

with 85% closed-loop earth connections (46% vertical and 38% horizontal) and 15% 

open-loop systems (groundwater).31

Geothermal energy can be used to make electricity—but that requires geothermal heat 

sources of 200–600°F (93–315°C). There is not that kind of geothermal resource 

available in Rhode Island. GSHP (term will be used to cover both GSHP and GHP 

generically, unless specific identification merits delineation) were not included in the 

REO analysis but investigated separately. 

To understand the advantages of using the geothermal resource, it might be best to look 

first at the framework that it will be used in. Heat pumps are an energy efficient HVAC 

equipment option that can be used as an energy saving alternative to conventional HVAC 

boilers, furnaces, and air conditioners. Heat pumps use electricity to move heat from a 

cool space to a warm space, making the cool space cooler and the warm space warmer. 

The most common type of heat pump is an air-to-air or air-source heat pump.

GHPs operate at higher efficiencies than air-source heat pumps (under most operating 

conditions) because they start with a higher temperature source in winter (in the example, 

52oF ground temperature versus 15oF air temperature) and a lower temperature “sink” in 

summer (for example, 60oF ground versus 95oF air). They use anywhere from 25%–50% 

less energy than a conventional heating and cooling system.32

3.11.1 Geothermal Resource Characteristics

The earth provides a continuous RE resource that can be tapped to meet all or most of 

building heating and cooling loads, and in some cases, even hot water loads. GSHP

systems take advantage of the temperature differential between the earth’s surface 

temperature and building loads versus the earth’s nearly constant temperature at some 

distance under the surface. Within 4–8 m of the earth’s surface, ground temperatures 

remain very stable despite the large fluctuations the earth’s surface undergoes due to the 

change of seasons in many regions of the United States. In the winter, this underground 

temperature is warmer than the air above it, and during the summer, it is cooler than the 

air above. A GSHP system exchanges heat with the steady temperature of the earth to 

meet building loads. In the winter, the heat pump removes heat from the ground and 

delivers it into the building. In the summer, the heat pump removes heat from the 

building and delivers it to the ground. GSHPs can offer a cost-effective technology 

solution to utilizing the heat of the earth to meet building loads. Overall, system 

performance and economics are improved at locations that have both a heating load and 

cooling load, such as NAVSTA Newport. 

If a water source is available, it should be evaluated as an option as it can enhance the 

performance of a system in several ways. Water has a considerably higher heat capacity 

at 4.186 Kj/(Kg °K) than any of the soil types shown in Table 8, so it can store heat and 

 31 RETScreen International. “Clean Energy Project Analysis: RETSCREEN® Engineering & Cases Textbook.” Clean 

Energy Support Center. www.retscreen.net. Accessed September 30, 2011. 32 NAHB Research Center. “Types of Equipment -Heating and Cooling.” 

http://www.toolbase.org/PDF/DesignGuides/MDL_8_MechanicalSystems.pdf. Accessed September 30, 2011. 
30

transfer it better than the soils. Water’s heat capacity is even higher than granite. Though 

some of water’s other properties are lower than those of the various soil types, water’s 

high heat capacity make it a useful ground loop thermal source. Also, in water source 

systems, after the water has completed its thermal exchange in the building, it is returned 

to the water source and all of its heat is removed, not just the partial heat removal that 

occurs through a heat exchanger in the ground source systems.

The soil characteristic profile is a key component of any initial screening for GSHP 

applications. The American Society of Heating, Refrigerating and Air-Conditioning 

Engineers (ASHRAE) recommends site investigations and sample boreholes to 

objectively evaluate the type of geo-exchange system best suited to a site. 

Table 8. Soil Types Defined in the GSHP Model33

The graph at the left in Figure 19 displays the amplitude of the sinusoidal relationship 

and associated time lag of the ground temperature at several depths and the surface 

temperature. Notice that the ground temperature at 12 ft is below the air temperature

from about the 110th day to the 185th day of the year. This provides a useful temperature 

differential for a heat exchange system that will exhaust warm building air with cool 

ground temperatures during the summer months and the opposite in winter.

 33 Natural Resources Canada. "Soil Types." 2007. Reproduced with the permission of the Minister of Natural 

Resources Canada, 2011. http://www.retscreen.net/ang/home.php.
31

Figure 19. Seasonal cycles of surface versus underground soil temperatures34

Figure 20 illustrates the groundwater temperature gradient zones across wide swaths of 

the United States. A steady thermal source combined with fluctuating temperature-driven 

loads provide a useful temperature differential for geothermal systems to exploit. 

Geothermal systems are generally designed to use heat pumps to move heat from where it 

is not needed to where it is desired. The direction of this thermal energy flow may be

opposite in winter than during the summer.

Figure 20. Average temperature (°C) near the surface of the United States from 

groundwater measurements35

A more detailed assessment of Rhode Island soil and sub-soil components can be found 

in Appendix H along with descriptions of the various types of GSHPs and their common 

configuration.

 34 Shonder, J. “Geothermal Heat Pumps.” Presented at FEMP Renewable Energy Workshop, NREL, 2004. 35 Blackwell, D.D.; Richards, M. (2004). “U.S. Portion of the Geothermal Map of North America.” American Assoc. 

Petroleum Geologist. http://smu.edu/geothermal/heatflow/surtemp.htm. Accessed October 2, 2011. 

Surface versus underground Seasonal soil temperature versus depth 

temperature time lag

 
32

3.12 Landfill Gas

The United States has approximately 2,300 municipal solid waste (MSW) facilities or 

landfills, and currently about 55536 of these sites are utilizing the landfill gas (LFG) for 

energy projects with roughly 350 of those generating electricity from the LFG.37

MSW, a common component of landfills, can contain significant portions of organic 

materials that may produce a variety of gaseous products as decomposition, fueled by 

anaerobic bacteria, thrives in this oxygen-free environment. Primary products of the 

decomposition of organic matter are carbon dioxide and methane. 

A brief 

overview of landfill emissions and landfill gas power plants are provided in Appendix I.

Methane is a hydrocarbon that is a primary component of natural gas (approximately 

83%–99%).38 LFG has a lower concentration of methane than natural gas 

(approximately 50%–80%); however, they are the third-largest human-related source of 

methane in the United States, accounting for 17% of all methane emissions in 2009.

39

Methane is lighter than air, soluble in water, and is a very potent GHG. Methane prevents 

the release of long wave radiation from the earth at night to a greater degree than most 

other GHGs resulting in a greater “greenhouse effect.” Methane is over 20 times more 

effective at trapping heat in the atmosphere than carbon dioxide. At capped landfills, 

methane can build up under the cap and reach dangerous pressure levels. Historically, the 

methane was flared at vent pipes throughout the landfill to prevent the pressure buildup. 

EPA requires that all large landfills install a collection system to minimize the release of 

methane.

LFG needs to be processed so it can be combusted directly or combined with natural gas 

for combustion. 

3.12.1 Landfill Gas Use

To make use of the LFG generated at a site, a collection system needs to be installed. The 

collection system typically consists of a series of wells drilled throughout the landfill and 

connected by a plastic piping system. The gas entering a gas collection system is 

saturated with water, and that water must be removed prior to further fuel processing 

through a technique known as “dewatering.” The typical “dry composition” of the lowBritish-thermal-unit gas is 57% methane, 42% carbon dioxide, 0.5% nitrogen, 0.2% 

hydrogen, and 0.2% oxygen. A significant number of other compounds can be found in 

trace quantities.40

 36 EPA. “An Overview of Landfill Gas Energy in the United States.” Landfill Methane Outreach Program. 

http://www.epa.gov/lmop/documents/pdfs/overview.pdf. Accessed October 2, 2011. 37 EPA. Technology Transfer Network Clearinghouse for Inventories & Emissions Factors. AP 42, 5th Edition, 

Volume I, Chapter 2: “Solid Waste Disposal.” http://www.epa.gov/ttn/chief/ap42/ch02/final/c02s04.pdf. Accessed 

October 2, 2011. 38 DOE, EERE. “Fuel Properties.” Alternative Fuels & Advanced Vehicles Data Center. 

http://www.afdc.energy.gov/afdc/fuels/properties.html. Accessed October 2, 2011. 39 EPA. “An Overview of Landfill Gas Energy in the United States.” Landfill Methane Outreach Program. 

http://www.epa.gov/lmop/documents/pdfs/overview.pdf. Accessed October 2, 2011. 40 California Energy Commission. “Landfill Gas Power Plants.” http://www.energy.ca.gov/biomass/landfill_gas.html.

Accessed October 2, 2011.
33

Depending on the quantity of LFG collected and other site factors, the LFG can be put to 

use in a number of energy applications, including:

• Electricity generation—combusted to generate electricity for on-site use or 

sale to the utility electric grid

• Direct use—combusted to replace or offset the use of another fuel in a boiler, 

kiln, or other thermal application

• Cogeneration (aka combined heat and power)—combusted for use in 

generating both electricity and thermal energy 

• Alternate fuels—converted to other useful energy forms, such as medium- or 

high-British-thermal-unit fuel, compressed-to-liquefied form, or methanol.

3.12.2 McAllister Point Landfill

McAllister Point, an 11-acre site along the shore north of the main campus, is a capped 

landfill at NAVSTA Newport. The site was an active landfill from 1955 to the mid-1970s 

and accepted wastes consisting primarily of domestic refuse, acids, solvents, paint, waste 

oil, and oil contaminated with polychlorinated biphenyls (PCBs).41 Of primary concern 

with any activities on this site are the potential impacts of the disturbance of the cap and 

the material underneath as surface water (i.e., rain and snowmelt) and groundwater flow 

towards the Narragansett Bay. Disturbances to the landfill have the potential to increase 

the leaching rate into the bay. Disturbances could also increase the migration of gases, 

such as methane, into the air. Also of concern are a number of private wells within a 3-

mile radius of the landfill that provides drinking water to approximately 4,800 people and 

irrigation water for around 200 acres of land.42

Figure 21. McAllister Point Landfill

Source: Google Earth

 41 EPA. “Waste Site Cleanup & Reuse in New England.” 

http://yosemite.epa.gov/r1/npl_pad.nsf/51dc4f173ceef51d85256adf004c7ec8/a48c071b6a314e1c8525691f0063f6dd?O

penDocument&Highlight=0%2Cnewport. Accessed October 2, 2011. 42 EPA. “Waste Site Cleanup & Reuse in New England.” 

http://yosemite.epa.gov/r1/npl_pad.nsf/51dc4f173ceef51d85256adf004c7ec8/a48c071b6a314e1c8525691f0063f6dd?O

penDocument&Highlight=0%2Cnewport. Accessed October 2, 2011.
34

McAllister Point was investigated in 1991, and elevated levels of petroleum 

hydrocarbons were found in the soils. This lead to a series of studies, plans, and decisions 

to develop treatments to address lateral flow of groundwater, reduce leachate into the 

near-shore marine environment, and reduce GHGs. The site continues to be monitored for 

groundwater migration, vent gas, and ambient air conditions to ensure that emissions are 

within acceptable parameters. The most recent Five-Year Review43 indicates the source 

control remedy is complete and groundwater, vent gas, and ambient air monitoring is 

ongoing. Recent groundwater monitoring annual results show few detections of volatile 

organic compounds and semi-volatile organic compounds; minor exceedences of the 

maximum contaminant level for organic compounds and some metals have been 

observed. Any consideration of this site for a LFG electricity-generating facility would 

need to begin with the general monitoring requirements outlined in the long-term 

monitoring program (LTMP).

44

Any alternative use of the McAllister Landfill (beyond its current use) would involve 

obtaining permission from EPA and other regulatory authorities as impacts to air quality 

and runoff into Narragansett Bay would need to be addressed.

3.12.3 McAllister Point as Potential Wind Turbine Site

The variation in the wind speeds between the collected data at Coddington Point and 

Tank Farm #4 (see Appendix A) points to well-exposed NAVSTA Newport sites along 

the Narragansett Bay as more likely having a greater wind resource than the inland tank 

farm sites. During the site visit, McAllister Point was raised a potential location for siting 

a utility-scale wind turbine. 

As shown in Figure 22, the site has reasonable fetch across the water in the south-westnorth arc, which helps to minimize surface-roughness-caused turbulence. 

Figure 22. McAllister Point Landfill with view to the south-west-north arc

Source: Google Earth

 43 EPA. “Five Year Review Report for Naval Station Newport.” Section 2.4.2. 

http://www.epa.gov/region1/superfund/sites/netc/457973.pdf. Accessed October 2, 2011. 44 EPA. “Five Year Review Report for Naval Station Newport.” Section 2.16. 

http://www.epa.gov/region1/superfund/sites/netc/457973.pdf. Accessed October 2, 2011.
35

It is unknown how the regulatory authorities, such as EPA, Rhode Island Coastal 

Resource Management Council, and Rhode Island Department of Environmental 

Management, might respond to a wind turbine project proposal for McAllister Point. It 

would be prudent to inquire about the nature of the issues to resolve before moving 

forward. A comparable wind turbine project placed on a landfill was successfully 

implemented in Hull, Massachusetts, in 2006.45

Due to the range of challenges to permit this facility for wind, NAVSTA Newport has 

determined they will not pursue wind on the McAllister Point Landfill.

The project, built on a 13-acre landfill 

comparable to McAllister Point’s 11 acres, provides a framework for consideration at 

NAVSTA Newport.

 45 Town of Hull, Massachusetts. “Hull Wind Turbine Information.” 

http://www.town.hull.ma.us/Public_Documents/HullMA_Light/Hull%20Wind%20Turbine. Accessed August 31, 2011.
36

4 Methodology

Using data from NAVSTA Newport, NREL performed analysis using geographic 

information systems (GIS) software, databases, Excel spreadsheet calculations, and 

optimization software called “Premium Solver,”46

4.1 Utility Energy Usage and Cost Data

which is an add-in to Excel. 

NAVSTA Newport provided NREL with annual utility use and cost (gas, electric, and 

oil) data for the previous year and other data for use in the analysis, such as square feet of 

building space. For information not supplied by NAVSTA Newport, standard values for 

the specific building type were obtained: cubic feet per minute of ventilation air as per 

ASHRAE Std 6247; gallons per day of hot water from Commercial Building Energy 

Consumption Survey (CBECS)48; and lighting levels as per the Illuminating Engineering 

Society of North America (IESNA) standard.

49

4.2 NAVSTA Newport Site Factors

NAVSTA Newport provided the following data for FY 2009 and FY 2010 for its 

buildings: site address, site latitude/longitude, total facility square footage (and when 

available, building loads, building sizes, and building primary use), and annual utility 

energy use and cost (gas, electric, and oil). National grid utility data was used for local 

energy cost and was also supplied by NAVSTA Newport.50 FY 2009 data was used in the 

analysis as representative data. This site information was combined with site-specific 

resource and incentive information from NREL's RE resource databases.51

The analysis was conducted with and without tax-based incentives. To do this, DSIRE 

was used to estimate the installed cost (including incentives and depreciation 

timeframe).

NAVSTA 

Newport did not provide an inventory of waste streams for use in the biomass fuel 

assessment, so only feedstocks from the surrounding area were considered. 

52

4.3 Renewable Resource and Technology Cost Data

A typical corporate tax liability structure in the 35% tax bracket was 

assumed for estimating the effects of business ITC and accelerated depreciation.

The RE resources associated with NAVSTA Newport were obtained from the NREL GIS 

database of solar, wind, weather, and biomass resources.

53

 46 Frontline Solvers. “Premium Solver Pro for Excel.” http://www.solver.com/pspro.htm. Accessed October 2, 2011. 47 ANSI/ASHRAE Standard 62.1-2007. “Ventilation for Acceptable Indoor Air Quality American Society of 

Refrigeration Air Conditioning and Heating Engineers.” Atlanta, GA: ASHRAE. 48 Federal Energy Management Program (FEMP). “Annual Supplement to Handbook 135.”

http://www1.eere.energy.gov/femp/information/download_blcc.html. Accessed May 2010. 49 IES HB-9-2000. “IESNA Lighting Handbook.” New York: IES. 50 Reichert, J. Email. NAVSTA Newport, Newport, RI, 4 May 2010. 51 NREL. “Dynamic Maps, GIS Data, & Analysis Tools.” http://www.nrel.gov/gis/. Accessed May 2010. 52 DSIRE. www.dsireusa.org. Accessed May 2010. 53 NREL. “Dynamic Maps, GIS Data, & Analysis Tools.” http://www.nrel.gov/gis/. Accessed May 2010.
37

NREL estimated the cost of each technology to be evaluated at each building and 

incorporated the effects of incentives that may be available from state governments, 

utilities, or others. Incentives will be as listed in DSIRE.

54

NREL employed simple annual-average algorithms to calculate energy delivery as a 

function of RE resources based on efficiency models. NREL calculated associated energy 

cost savings based on energy use and cost information supplied by NAVSTA Newport. 

NREL staff compiled the 

incentives available for each technology at NAVSTA Newport from DSIRE.

Estimates for the installed cost of RE technologies were based on NREL’s project 

experience and cost estimating manuals (RS Means Green Building: Project Planning and 

Cost Estimating, 201055). NREL estimated annual O&M costs as a fraction of installed 

cost or as a multiplier on energy production as reported in the Power Technologies 

Energy Data Book56 and including staff project experience. Costs are adjusted according 

to the City Cost Adjustments for Newport, Rhode Island, published by RS Means.

57

4.4 Economic Factors

NAVSTA Newport was interested in viable long-term RE options, so NREL performed a 

25-year LCC analysis with future costs discounted to their present value. Twenty-five 

years was selected as the analysis period because it is the maximum allowed by 

10CFR43658

4.5 Renewable Energy Optimization

for electrical and mechanical systems, and these systems are expected to last 

that long. In order to model costs that are not constant from year to year, such as 

accelerated depreciation, a 25-year cash flow analysis was prepared. NREL calculated an 

LCC of all RE technologies combined at the site but also reported a payback period (25 

years or less) as figures-of-merit to assess the cost effectiveness of each individual 

technology. Other results include rate of return and percentage of RE use at each site. 

NREL’s REO tool was used to determine the combination of RE technologies that 

minimize LCC for energy at the site. The best mix of RE technologies depends on several 

factors, including RE resource availability; technology cost and performance; state, 

utility, and federal incentives; and economic parameters (e.g., discount rate and inflation 

rates). Each of these factors was considered in this analysis. Due to the close proximity 

and same utility pricing among the buildings at NAVSTA, the location was optimized 

rather than individual buildings. 

 54 DSIRE. www.dsireusa.org. Accessed May 2010. 55 RS Means. “Green Building Project Planning and Cost Estimating,” 2010.

http://www.rsmeans.com/bookstore/detail.asp?sku=67338A, Accessed March 2011. 56 NREL. Power Technologies Energy Data Book, Edition Four. http://www.nrel.gov/analysis/power_databook/. 

Accessed May 2010.

57 RS Means. “Green Building Project Planning and Cost Estimating,” 2010.

http://www.rsmeans.com/bookstore/detail.asp?sku=67338A, Accessed March 2011. 58 GPO Access. 10CFR436. http://ecfr.gpoaccess.gov/cgi/t/text/textidx?c=ecfr&tpl=/ecfrbrowse/Title10/10cfr436_main_02.tpl. Accessed October 2, 2011.
38

To conduct the analysis, NREL applied its REO tool and several other programs to 

systematically analyze: 

• Energy needs of each building or set of buildings 

• Available RE resources at the base 

• Appropriate mix of RE technologies based on the building loads and the 

available RE resources 

• LCCs of appropriate RE solutions compared to LCCs of the base case at each 

site

• Energy savings for RE solutions compared with today’s energy mix (base 

case).

The installed cost (including the effects of incentives and tax depreciation), energy 

performance, cost savings, and LCC effectiveness were estimated for the seven RE

technologies. After estimating the cost and savings associated with each RE measure, the 

size of each technology was adjusted to minimize LCC. 

Additional investigation and analyses were conducted, without use of the REO tool, for 

other RE technologies of particular interest to NAVSTA Newport, including: 

• Biofuels from algae

• Tidal current power

• GSHPs.

4.6 Iterative “Solving”

Unlike other tools, the NREL REO tool takes into account the effect of the other RE 

systems being optimized and adjusts sizing accordingly. For example, if REO finds that 

adding a significant amount of daylighting to a building is LCC effective, the impacts of 

adding daylighting may increase the heating load in the winter and decrease the cooling 

load in the summer and the HVAC system would need to compensate accordingly. The 

REO tool accounts for this compensation when sizing the daylighting and re-calculates 

the energy impacts of the daylighting. REO does this for all the RE technologies.

Using several RE technologies at NAVSTA Newport reduces the use of purchased 

energy. This improves energy security and provides a greater hedge against price or fuel 

supply fluctuations than using a single RE technology. This benefits federal agencies, 

which are particularly vulnerable to price and supply fluctuations because their energy 

and O&M budgets tend to be fairly stable or fixed and cannot easily accommodate rapid 

energy price increases. 

Once energy savings (in therms and kilowatt-hours) for each RE technology were 

determined with the REO tool, carbon dioxide emissions savings were calculated. DOE’s 

multipliers for carbon dioxide emissions per kilowatt-hour of electricity use were based 
39

on the local power plant fuel source mix. A standard multiplier for carbon dioxide 

emissions per therm of natural gas consumption was used. 59

4.7 GIS Data on Renewable Energy Resources

NREL evaluated RE technologies using a GIS database of RE resource information60

NREL datasets used in the analysis include:

to 

represent the magnitude of a RE resource in the area.

• Solar radiation (40 x 40 km grid)

• Horizontal, south-facing vertical, tilt = latitude

• Wind energy (200 m x 1,000 m grid)

• Biomass resources

• Illuminance for daylighting

• State and utility incentives and utility policy61

• Temperature, heating, and cooling degree days

• City cost adjustments62

• Installed hardware costs63

• Economic parameters (e.g., discount rate and inflation rate).

64

4.8 Optimization Technique

The objective of the optimization is to minimize LCC. Using NAVSTA Newportsupplied inputs on energy usage, cost, building types, and estimated costs and savings 

associated with each RE measure, the LCC of energy production from each RE 

technology was determined. Premium Solver65

• Kilowatts of PV 

was then used to adjust each of the 

following variables to minimize LCC:

• Kilowatts of wind power

• Square feet of SVP

 59 EPA. “Clean Energy, Greenhouse Gas Equivalencies Calculator.” http://www.epa.gov/cleanenergy/energyresources/refs.html. Accessed May 2010. 60 NREL. “Dynamic Maps, GIS Data, & Analysis Tools.” http://www.nrel.gov/gis/. Accessed May 2010. 61 DSIRE. www.dsireusa.org. Accessed May 2010. 62 RS Means. “Green Building Project Planning and Cost Estimating,” 2010.

http://www.rsmeans.com/bookstore/detail.asp?sku=67338A, Accessed March 2011. 63 DOE “Building Energy Databook.” http://buildingsdatabook.eren.doe.gov/. Accessed May 2010. 64 FEMP. “Annual Supplement to Handbook 135”

http://www1.eere.energy.gov/femp/information/download_blcc.html. Accessed May 2010. 65 Frontline Solvers. “Premium Solver Pro for Excel.” http://www.solver.com/pspro.htm. Accessed October 2, 2011.
40

• Square feet of solar water heating

• Square feet of solar thermal (parabolic troughs) and kilowatts of solar thermal 

electric 

• British thermal units per hour of biomass boiler capacity and kilowatts of 

biomass electric using:

o Combustion

o Gasification

o Anaerobic Digestion

• Percentage of office, gymnasium, and warehouse roofs to be occupied by 

daylighting skylights.

The solver routine calculates the change in LCCs associated with a change in the size of 

each of the RE technologies. It then moves in the direction of LCC by an amount 

determined by a quadratic approximation (Figure 23). 

Figure 23. Illustration of the solver routine

Illustration by Jim Leyshon, NREL

The solver routine finds the minimum LCC in 10 variables, but only two variables can be 

illustrated in this two-dimensional figure. An increase and decrease in the size of each RE 

component is used to indicate the direction of reducing LCCs. The solver routine 

involved the following parameters: precision—value of energy use 0.0 ± 0.0001; 

convergence—change in LCC less than $0.0001 for five iterations; quadratic 

extrapolation to obtain initial estimates of the variables in a one-dimensional search; 

central derivatives used to estimate partial derivatives of the objective and constraint 

functions; and Newtonian Search Algorithm used at each iteration to determine the 

direction to search.
41

4.9 Results of LCC Optimization

The key result of the analysis is the size of each RE measure that minimizes LCC for 

NAVSTA Newport. Results indicate that daylighting can be cost effective at NAVSTA 

Newport, but attention must be paid to avoid excessive heat loss through skylights. SVP 

is cost effective due to the long heating season. Solar water heating is viable due to the 

combination of solar resource and the application at high load buildings. Wind is viable 

due to the consistency of seasonal and diurnal (daily profile) winds near the water. PV 

depends heavily on local, state, and federal incentives to be cost effective and is 

marginally just outside the threshold of being not cost effective at current incentive 

levels.

4.10 LCC

LCC is calculated by adding initial cost to any annual costs discounted to their present 

value. Annual costs include maintenance, fuel (as in the case of biomass), standby 

charges from the utility, payments to the utility associated with the difference between 

retail and delivered power, and any production incentives or other cash flows.

LCC = Cinitial + (Senergy – CO&M – Cbiomass fuel) pwf25 + (Sprod incentive) pwfprod incentive

where 

LCC = life cycle cost

Cinitial = initial cost of the RE system

Senergy = annual savings in electricity and natural gas purchased from the utility

CO&M = annual cost of RE systems’ O&M

Cbiomass fuel = annual cost of delivering biomass fuel to the site

pwf25 = present worth factor for future savings stream for 25-year lifetime and 

3% real discount rate (specified by NIST for 2008).

66

Sprod incentive = annual revenue from production incentive

[Note: real discount rate 

(3.0%) = nominal discount rate – inflation rate (4.8% – 1.8%)]

pwfprod incentive = present worth factor associated with the term of the production 

incentive 

Simple payback (SPB) period is not a good criterion because it does not include the 

analysis period or term of production incentives, but it is a useful indicator of general 

viability and is given by the equation:SPB = C/S

 66 Platts. http://www.platts.com/Home.aspx. Accessed May 2010.
42

General O&M costs are escalated at the general inflation rate, and annual costs for fuels 

and electricity are inflated according to census region and fuel type. All annual costs are 

discounted according to discount rate. The factors are provided in Table 9.

67

Table 9. Economic Parameters Used in LCC Calculations

Discount Rate 4.8%

General Inflation Rate 1.8%

Corporate Tax Rate (for case with 

incentives)

35.0%

Depreciation Schedule (for case with 

incentives)

Year 1 2 3 4 5 6

Fraction 0.200 0.320 0.192 0.115 0.115 0.058

4.11 Carbon Dioxide Emissions Impact

Electricity saved from daylighting, wind power, and SVP in kilowatt-hours was totaled. 

This total was multiplied by the appropriate carbon dioxide offset factor for the zip code, 

02841, of the base. The multipliers were taken from the EPA online application.68

Therms saved/produced for daylighting (negative), SVP, and solar water heating were 

multiplied by the carbon dioxide offset factor for natural gas of 11.70 lbs/therm.

 

69

4.12 Land Use Requirements

Land use requirements are established for solar PV, wind energy, solar thermal, and solar 

thermal electric technologies. Land use requirements of the other technologies are not 

included, but many of these fit within the building or on the building shell. Many 

locations with cost-effective applications of solar or wind are constrained by the site size. 

 67 FEMP. “Annual Supplement to Handbook 135.”

http://www1.eere.energy.gov/femp/information/download_blcc.html. Accessed May 2010. 68 EPA, “Clean Energy.” http://www.epa.gov/cleanenergy/energy-and-you/how-clean.html. Accessed June 2011. 69 EPA. “Calculations and References.” http://www.epa.gov/cleanenergy/energy-resources/refs.html. Accessed June 

2011.
43

5 Data Summaries 

5.1 GIS Data

The following resource data were drawn from NREL’s GIS database for use in the REO 

analysis.

Table 10. GIS Resource Data

GIS Data

Latitude 41.519400°

Longitude -71.327250°

Heating Degree Days (65°F) 5,629

Cooling Degree Days (65°F) 729

Annual Average Solar Tilt = Latitude 4.34 kWh/m2/day

Annual Max Solar Tilt = Latitude 6.09 kWh/m2/day

Annual Average Solar Horizontal 3.44 kWh/m2/day

Wind Power Density at 50 m 336 W/m2

Annual Solar Vent Preheat Delivery 454 kWh/m2/day

Annual Direct Solar on East-West 1-Axis Tracker 2.69 kWh/m2/day

Biomass, Residues Within 50 Miles

Crops 0

Manure 0

Forest 25,796 tons/year

Primary Mill 30,871 tons/year

Secondary Mill 359,928 tons/year

Urban 0

Landfill 0

Domestic Waste Water Treatment 0

Energy Crops on Conservation Reserve Program

Land 0

Total 416,595 tons/year
44

Illuminance Data

March

9a.m. 31 fc

11a.m. 53 fc

1p.m. 56 fc

3p.m. 41 fc

5p.m. 15 fc

June

9a.m. 40 fc

11a.m. 66 fc

1p.m. 79 fc

3p.m. 71 fc

5p.m. 48 fc

September

9a.m. 25 fc

11a.m. 52 fc

1p.m. 65 fc

3p.m. 56 fc

5p.m. 29 fc

December

9a.m. 11 fc

11a.m. 28 fc

1p.m. 29 fc

3p.m. 15 fc

5p.m.0
45

5.2 Incentive Data

Incentives offered by federal and state governments, local utilities, and private 

organizations have a huge effect on renewable project economics and need to be taken 

into account even at this early planning stage. There are four types of incentives that are 

considered for each technology: federal business ITC (percent of cost); state tax credit 

(percent of cost); rebate ($/W or percent of cost); and production incentives ($/kWh 

produced). The incentives used in this analysis are listed in Table 11 for each site and 

each technology. Descriptions of incentives available at each facility are taken from 

DSIRE.

70

Table 11. Incentives*

It is important to note that most incentive and rebate programs have 

requirements, such as minimum or maximum size limitations or specific technology 

specifications, which a system must meet in order to qualify. 

*Note: The net-metering limit for solar or wind is 1,650 kW.71

There are several important points to note in regards to the incentives. Tax credits such as 

the federal business energy tax credit are for commercial entities that pay taxes and are 

 70 DSIRE. http://www.dsireusa.org/. Accessed October 20, 2011. 71 National Grid. https://www.nationalgridus.com/narragansett/business/energyeff/4_net-mtr.asp. Accessed October 2, 

2011.

Incentive Type Incentive 

Amount

Name

Wind

Tax Incentive (% capital cost) 30 Federal Business Energy Tax Credit (100 kW limit)

People's Power and Light Renewable Energy Certificate Incentive

(RECs are not claimable by site if this program is used)

Solar Ventilation Preheating

Tax Incentive (% capital cost) 30 Federal Business Energy Tax Credit

National Grid Solar Thermal Rebate Program

(Up to max of 50% installed cost or $100,000 per project)

Solar Water Heating

Tax Incentive (% capital cost) 30 Federal Business Energy Tax Credit

National Grid Solar Thermal Rebate Program

(Up to max of 50% installed cost or $100,000 per project)

Photovoltaics

Tax Incentive (% capital cost) 30 Federal Business Energy Tax Credit

People's Power and Light Renewable Energy Certificate Incentive

(RECs are not claimable by site if this program is used)

Concentrating Solar Power

Tax Incentive (% capital cost) 30 Federal Business Energy Tax Credit

Biomass

Tax Incentive (% capital cost) 10 Federal Business Energy Tax Credit

Geothermal Heat Pump

Tax Incentive (% capital cost) 10 Federal Business Energy Tax Credit

Production Incentive ($/therm) 3

Renewable Energy Certificate 

Incentive ($/kWh) 0.03

Renewable Energy Certificate 

Incentive ($/kWh) 0.03

Production Incentive ($/therm) 3
46

thus eligible for a tax credit. As a federal entity, NAVSTA Newport does not pay taxes 

and cannot qualify for the tax credit unless there is third-party ownership of the RE 

system. 

There is a Rhode Island tax credit that is available for 25% of PV and wind systems 

costing up to $15,000. For SWH and GHPs, the 25% tax credit is available with a system 

cost limit of $7,000. Given the size limitation of the Rhode Island tax incentive relative to 

the size of RE systems considered, it should not be used as a decision-making factor. 

However, when moving forward with an RE project among the eligible technologies with 

third-party ownership, the tax credit for a portion of the project can serve as a minor 

incentive.

5.3 Economic Data

The following economic parameters are used in the installed cost and LCC calculations.

Table 12. Economic Parameters

Discount Rate 4.6%

Fuel Escalation Rate 5.8%

Electric Escalation Rate 3.3%

General Inflation Rate 3.4% 

City Cost Adjustment Factor 1.025
47

5.4 Site Data

The following utility and site data was provided by NAVSTA Newport and used to frame 

the optimization.

Table 13. Site Data

Utility National Grid

Annual Electric Use1 105,735,000 kWh

Annual Electric Cost1 $12,683,475

Annual Natural Gas Use1 4,780,340 therms

Annual Natural Gas Cost1 $5,533,113

Annual Fuel Oil Use1 159,810 therms

Annual Fuel Oil Cost1 $279,716

Total Building Size 3,534,850 ft2

Number of Buildings Used in REO 54

1 FY 2009 data

5.5 Technology Data

Initial cost, efficiency, and O&M cost for each of the RE technologies are characterized 

according to the cost and performance data reported in the Power Technologies Energy 

Data Book72 and in “Renewable Energy Technology Characterizations.”73

As the REO software is an optimization tool, if there is not a cost-effective option, it 

returns a system size of zero with costs of zero. In these cases, a representative system 

size has been input to demonstrate the realm of the results (i.e., in some cases the simple 

payback is negative or more than 50 years).

 

5.5.1 Daylighting

A complete daylighting system consists of apertures to admit and distribute solar light 

and a controller to modulate artificial light to achieve energy cost savings. There are no 

scheduled maintenance requirements, but skylights may increase roof maintenance. Table

14 lists the details of the daylighting analysis, including skylight area as a percentage of 

roof area, cost, annual energy delivery, annual cost savings, and payback period. 

Daylighting was found to be cost effective for NAVSTA Newport. Although skylights 

reduce building insulation levels, the cost of the heat lost through the skylights is much 

smaller than the savings realized from reduced electric light use. 

An implication from implementing daylighting is that more heat will be required in the 

winter due to the reduction of waste heat from electric lighting. The added 59,755 therms 

for implementing daylighting is due to the impact of reduced waste heat from electric 

 72 NREL. “Power Technologies Energy Data Book.” http://www.nrel.gov/analysis/power_databook. Accessed October 

2, 2011.

73 DOE. “Renewable Energy Technology Characterizations.” EPRI Topical Report No. TR-109496. 

http://www1.eere.energy.gov/ba/pba/tech_characterizations.html. Accessed October 2, 2011.
48

lighting that actually offsets a portion of the heating load in a typical office and other 

types of buildings. This offsets a portion of the savings from daylighting. Overall, the net 

reduction in energy use from implementing daylighting is the equivalent of 494,000 

kWh/yr, resulting in a net cost savings of approximately $59,300/yr.

Table 14. Daylighting Analysis

5.5.2 Wind

NAVSTA Newport intends to develop their wind potential in phases—Phase I will 

consider properties “inside the fence line,” and Phase II will consider properties “outside 

the fence line.”74

 74 Reichert, J. Email. NAVSTA Newport, Newport, RI, 25 August 2009.

Per NAVSTA Newport’s plans for Phase I of its site development for 

wind, an average installed cost of $3,800/MW was assumed. Table 15 lists details of the 

wind power analysis, including size of the wind energy facility (kW), cost, annual energy 

delivery, annual cost savings, and payback period. There was variability in the turbine 

output depending upon specific siting at NAVSTA Newport. Overall, wind was found to 

be cost effective at NAVSTA Newport due to good resource and sufficient incentives. 

Characteristic Measurement Units

Daylighting Skylight/Floor Area Ratio 1.4% %

Total Skylight Area 79,572 ft2

Annual Electric Savings 2,244,628 kWh/yr

Annual Natural Gas Savings -59,755 therms/yr

Daylighting Capital Cost 3,261,134 $

State Tax Credit - $

Federal Tax Credit - $

Rebate - $

Daylighting Cost w/ Incentives 3,261,134 $

Daylighting Annual Cost Savings 202,747 $/yr

Daylighting Payback Period 16.1 yrs
49

Table 15. Wind Analysis

5.5.3 Solar Ventilation Preheating

Table 16 lists the details of the SVP analysis including size of the transpired collector, 

cost, annual energy delivery, annual cost savings, and payback period. SVP was found to 

be cost effective for NAVSTA Newport. 

Table 16. Solar Ventilation Preheating Analysis

Characteristic Measurement Units

Wind Turbine Swept Area 19,085 m2

Wind Turbine Swept Area 205,429 ft2

Wind Capacity 9,000 kW

Wind Initial Cost 34,200,000 $

Wind Rebate - $

Wind Production Incentive - $/yr

Wind State Tax Credit - $

Wind Federal Tax Credit 10,260,000 $

Wind Initial Cost w/ Incentives 23,940,000 $

Wind Net Metering Limit (Up To) 1,650 kW

Wind Annual Energy Delivery 23,843,000 kWh/yr

Capacity Factor 30.2 %

Wind Annual Cost Savings 2,861,160 $

Wind Annual O&M Cost 71,100 $/yr

Wind Payback Period 8.6 yrs

Characteristic Measurement Units

SVP Ventilation Rate 2,228,280 CFM

Available Wall Area Constraint 298,104 ft2

Low Flow Constraint 1,114,140 ft2

Suggested Size 557,070 ft2

Solar Vent Preheat Area 260,417 ft2

Annual Gas Savings 468,632 therms/yr

Initial Cost 11,066,261 $

SVP Rebate - $

Production Incentive - $/yr

SVP State Tax Credit - $

SVP Federal Tax Credit 3,319,854 $

Solar Vent Preheat Cost w/ Incentives 7,746,325 $

Annual Utility Cost Savings 597,402 $/yr

Solar Vent Preheat Payback Period 13.0 yrs
50

5.5.4 Solar Water Heating

Table 17 lists the details of the solar hot water analysis, including size of the solar water 

heating system, cost, annual energy delivery, annual cost savings, and payback period. 

Solar hot water was found to be cost effective for NAVSTA Newport. 

Table 17. Solar Water Heating Analysis

Characteristic Measurement Units

Hot Water Use 223,968 gal/day

Suggested Solar Hot Water size 160,578 ft2

Solar Water Heating Area 138,409 ft2

Solar Water Heating Heat Delivery 298,085 therms/yr

Solar Water Heating Initial Cost 13,522,848 $

SWH Rebate - $

Production Incentive - $/yr

Solar Hot Water State Tax Credit - $

Solar Hot Water Federal Tax Credit 4,056,854 $

Solar Water Heating Cost w/ Incentives 9,465,994 $

Solar Water Heating Fuel Savings 465,758 therms/yr

Solar Water Heating Annual Utility Cost Savings 564,850 $/yr

Solar Water Heating O&M Cost 67,614 $/yr

Solar Water Heating Payback Period 19.0 yrs
51

5.5.5 Photovoltaics

Table 18 lists the details of the PV analysis, including size of the PV, cost, annual energy 

delivery, annual cost savings, and payback period. PVs were not found to be cost

effective at NAVSTA Newport due to a payback period of 25.8 years. Without 

incentives, the payback period increases to 36.9 years.

The installed cost of PV systems, particularly the module cost, has been coming down 

consistently in recent years and may fall below the 25-year payback threshold in the near

future. A sensitivity analysis indicated that for a 10% decrease in installed system cost, 

the payback decreased by approximately 2.6 years. Similarly, a 10% increase in the cost 

of electricity from the National Grid or a 10% increase in PV module efficiency would 

decrease the payback by approximately 2.5 years.

Table 18. PV Analysis

5.5.6 Concentrating Solar Power

Table 19 lists the details of the solar thermal analysis, including size of the array, cost, 

annual energy delivery, annual cost savings, and payback period. Concentrating solar 

power was not found to be cost effective at NAVSTA Newport due to the relatively poor 

solar resource. Overall, this or any form of “concentrating” solar technology works best 

in a drier climate with less humidity and few cloudy or overcast days.

Characteristic Measurement Units

PV Rating 5,000 kW

PV Size 320,238 ft2

PV Initial Cost 25,625,000 $

PV Rebate - $

PV Production Incentive - $/yr

PV State Tax Credit - $

PV Federal Tax Credit 7,687,500 $

PV Initial Cost w/ Incentives 17,937,500 $

Net Metering Up To 1,650 kW

PV Annual Energy Delivery 6,095,131 kWh/yr

Capacity Factor 18.1 %

PV Annual Utility Cost Savings 731,416 $

PV Annual O&M Cost 36,571 $/yr

PV Payback Period 25.8 yrs
52

Table 19. Concentrating Solar Power Analysis

5.5.7 Biomass

Several technologies are available to convert biomass feedstocks into heat and electricity. 

In this analysis, we consider gasification of dry biomass feedstocks such as crop or wood 

mill waste available in the area. Table 20 lists the details of the biomass gasifier analysis,

including size of the gasifier, cost, annual energy delivery, annual cost savings, and 

payback period. 

Biomass gasification was not found to be cost effective at NAVSTA Newport because 

the cost of fuel and annual O&M exceeds the value of energy produced. 

Characteristic Measurement Units

Concentrating Solar Power Area 10,000,000 ft2

Solar Heat Delivery 15,736,487 therms/yr

Concentrating Solar Power Cogeneration Size 10,000 kW

Thermal Storage (therms) -

Concentrating Solar Power Gas Savings 5,089,582 therms/yr

Concentrating Solar Power Electric Delivery 18,615,000 kWh/yr

Concentrating Solar Power Capacity Factor 21.3 %

Concentrating Solar Power Annual Utility Cost Savings 7,024,734 $/yr

Concentrating Solar Power Initial Cost 765,162,500 $

Rebate - $

Production Incentive - $/kWh

State Tax Credit - $

Federal Tax Credit 229,548,750 $

Concentrating Solar Power Cost w/ Incentives 535,613,750 $

Concentrating Solar Power O&M Cost 1,998,577 $/yr

Concentrating Solar Power Payback Period 106.6 yrs
53

Table 20. Biomass Gasifier Analysis

5.5.8 Accommodating Missing Data

The REO analysis was based on actual building size, building electricity usage, and

building heating energy as provided by NAVSTA Newport. The data was for the largest 

energy users on the campus. There were many smaller buildings not accounted for in this 

dataset resulting in the building cost and load totals being approximately half of the full 

campus load. To complete the REO analysis with more realistic results, NREL created 

four “big buildings” that combined to represent the energy and cost loads from the 

balance of buildings at NAVSTA Newport. These estimated loads and costs are shown in 

Table 21.

Table 21. Estimated Data

Characteristic Measurement Units

Biomass Gasifier Size 2 MMBTU

Biomass Gasifier SynGas Delivery 148,920 therms/yr

Biomass Initial Cost 922,500 $

Biomass Natural Gas Savings 148,920 therms/yr

Biomass Gasifier Annual Utility Cost Savings 175,227 $/yr

Tons of Fuel Used 1,986 tons

Area to Collect Fuel 38.4 mi2

Per Ton Fuel Cost 129.35 $/ton

Fuel Cost 256,840 $

Avoided Disposal Cost - $

State Tax Credit - $

Federal Tax Credit 92,250 $

Rebate - $

Biomass Gasifier Cost w/ Incentives 830,250 $

Biomass Gasifier O&M Cost 115,036 $/yr

Biomass Gasifier Payback Period Negative yrs

Building Name Size Electricity Natural Gas #2 Oil

ft2 kWh/yr $/yr therms/yr $/yr therms $/yr

Big Building A 739,175 11,428,584 1,371,430 684,090 712,410 2,307 2,458

Big Building B 739,175 11,428,584 1,371,430 684,090 712,410 2,307 2,458

Big Building C 739,175 11,428,584 1,371,430 684,090 712,410 2,307 2,458

Big Building D 764,935 13,397,450 1,607,694 684,090 712,000 2,307 2,455
54

6 Conclusions and Recommendations

6.1 Results

Overall, the REO results indicate that a combination of wind turbines, SVP, solar hot 

water heating, and daylighting minimizes the LCC of energy at NAVSTA Newport. 

These results can be viewed in Table 22. Low resource availability combined with 

current competing cost of energy (COE) limited state and utility incentives and prevented 

other RE generation from being cost effective over a 25-year period. 

The base case of continuing to purchase electricity and natural gas has zero initial cost 

but high annual cost, while the RE solutions case has high initial cost but reduced annual 

cost and a reduced LCC. The optimal solution reduces the 25-year COE from

$418.7 million to $371.7 million, thereby saving $47 million. 

In practice, many renewable technologies have lifetimes beyond 25 years. Daylighting 

benefits and savings, for example, will continue to accrue for the entire life of the 

building it is deployed in. NAVSTA Newport can reasonably expect some of the 

calculated savings to continue to accrue beyond the 25-year analysis period

Table 22. Sizes of Cost-Effective Renewable Energy Measures

Technology Size Units Electricity 

Offset

Percent 

Electricity 

Reduction

Fuel 

Offset

Percent 

Fuel 

Reduction

Annual 

Emission 

Reduction

25 - Year 

Emission 

Reduction

kWh/yr % therms/yr % lbs CO2/yr lbs CO2

Skylight/ Floor Area Ratio 1.4% % 2,244,628 2.1% -59,755 -1.2% 1,279,850 31,996,259

Wind Energy 9,000 kW 23,843,000 22.5% - - 21,019,315 525,482,875

Solar Vent Preheat 260,417 f t2 - - 468,632 9.5% 5,481,529 137,038,222

Solar Water Heating 138,409 f t2 - - 465,758 9.4% 5,447,912 136,197,801

PV 0 kW - - - - - -

Concentrating Solar Area 0 f t2 - - - - - -

Concentrating Solar Electric 0 kW - - - - - -

Biomass Gasifier Size 0 MBtu/hr - - - - - -

Biomass Gasifier Cogen Size 0 kW - - - - - -

Totals 26,087,628 24.6% 874,635 17.7% 33,228,606 830,715,157
55

Figure 24 outlines visually the overall size and potential energy offset of each technology 

in the optimized solution.

Figure 24. Energy delivery of each renewable energy technology per minimum life cycle 

cost

Table 23 provides a summary of the RE produced by these systems, in equivalent 

kilowatt-hour terms, initial cost to implement the optimized RE solution with and without 

incentives, the annual utility cost savings associated with those measures, and the simple 

payback period with and without incentives.

Table 23. Renewable Energy Solutions Case—Cost and Savings Summary

-5,000

95,000

195,000

295,000

395,000

495,000

595,000

695,000

795,000

Base Case (MMBtu/yr) RE Case (MMBtu/yr)

Annual Energy (MMbtu/yr)

Solar Vent Preheat Sold to Utility Daylighting 

Solar Water Heating Wind Photovoltaics 

Fuel Electric

Technology Equivalent 

Energy 

Offset

Percent 

Energy 

Reduction

Initial 

Investment with 

Incentives

Annual 

Savings

Simple 

Payback

Initial 

Investment 

W/O Incentives

Simple 

Payback

equiv kWh/yr % $ $/yr yrs $ yrs

Daylighting 2,244,628 0.9% 3,261,134 202,747 16.1 3,261,134 16.1

Wind Energy 23,843,000 9.5% 23,940,000 2,790,060 8.6 34,200,000 12.3

Solar Vent Preheat 13,730,918 5.5% 7,746,325 597,402 13.0 11,066,261 18.5

Solar Water Heating 13,646,709 5.4% 9,465,994 497,236 19.0 13,522,848 27.2

Totals 53,465,255 21.3% 44,413,453 4,087,445 11 62,050,243 15
56

6.2 Conclusions 

The REO analysis indicates that wind turbines, SVP, daylighting, and solar water heating 

are cost effective at NAVSTA Newport. An initial investment of around $44 million

would be required to implement these technologies and would result in utility cost 

savings of about $4 million per year. This project has an 11.9% rate of return and an 11-

year simple payback period. Implementing these measures would deliver roughly 21.3% 

of the site’s energy use from renewables. 

NAVSTA Newport desires to produce 25% of its base energy from renewable sources. 

Wind is the most cost-effective option at this site with paybacks 35% shorter than the 

next best option. Adding approximately 5.5 MW of wind, bringing the total to 14.5 MW, 

will enable the base to achieve its 25% RE goal. 

NAVSTA Newport has undertaken a number of energy efficiency audits and retrofits 

over the years and constructs new buildings with high efficiency goals. Nonetheless, 

upfront efforts to reduce energy consumption through a program of increased efficiency 

in operations and equipment combined with modest conservation measures can reduce 

overall consumption that significantly reduces the bottom line of RE implementation. For 

every 10% reduction in load, there is a corresponding 2.5% reduction in the number of 

kilowatt-hours that need to be generated to meet the same 25% RE goal. Therefore, 

before investing in RE generation, NREL recommends implementing all cost-effective 

energy efficiency measures. These can be identified through an energy efficiency audit. 

Conservation is an effective method for reducing energy consumption at little or no cost. 

The renewable projects recommended in this screening require additional analysis prior 

to implementation. The SVP and solar hot water recommendations are based on average

ventilation rates and hot water use for this building size and type. Further economic 

analysis based on actual ventilation rates and hot water use, as well as a site evaluation to 

determine building suitability, is recommended. An in-depth analysis of wind availability 

will more accurately predict actual savings. Although not included in this analysis, we 

also recommend exploration of LFG combustion as a potential self-generation 

opportunity. 

The remaining renewable technologies evaluated, biomass, PV, and solar industrial 

process heat, were not found to be cost effective over a 25-year period, mainly due to 

current COE, low resource availability in the area, and the level of incentives. However, 

there are many reasons for implementing renewable technologies besides cost. 

Renewables contribute to energy security and independence, provide an emission-free 

alternative to fossil fuels amid increasing concerns about climate change, and support 

national goals for increased RE use. 
57

6.2.1 Other Renewable Energy Technologies

While not a part of the optimization model, anaerobic digestion, biofuels from algae, 

marine-based hydro-generation (wave and tidal power), GSHPs, and LFG are also 

potential sources of RE. Each has its own challenges for potential use at NAVSTA 

Newport.

• Anaerobic digestion requires a large source of animal waste, sewage, or 

industrial effluent and is likely not applicable at NAVSTA Newport. 

• Biofuels from algae technologies are in the early stages of development and 

are many years away from off-the-shelf commercial technologies at 

competitive prices.75

• Conventional hydroelectric power generation is limited due to minimal 

elevation drop from the bay to the ocean. Marine-based hydro-generation 

(wave and tidal power) has potential in Newport, but the technology is still in 

the development stages. Newport’s tidal and wave resource is limited, and 

regulatory authorities make deployment very challenging. 

• GSHPs are viable options and warrant further assessment. GSHPs are a 

commercially available technology that work best within certain soil types, 

climate zones, and competing energy cost parameters and are framed for 

NAVSTA Newport in Appendix H.76

• LFG merits a more detailed investigation. The overall resource at McAllister 

Point is not large but may be large enough to have positive economics. 

Disturbance of contaminants and potential for leeching are critical issues that 

must be addressed to move forward.

Among the auxiliary technologies, it is prudent to focus on GSHPs first as, with adequate 

resource and appropriate soil conditions, it may prove to be a long-term thermal energy 

solution for particular buildings. 

 75 Darzins, A.; Driscoll, R. Telephone call. NREL, Golden, CO, 4 June 2010. 76 Shonder, J. Telephone call. Oak Ridge National Laboratory, Oak Ridge, TN, 8 June 2011.
58

Appendix A. Coddington Point Wind Data Analysis and 

Economic Projections

NAVSTA Newport, in conjunction with NREL and Naval Facilities Engineering Service 

Center (NFESC), has been actively engaged in assessing the wind resource through 

several ongoing efforts. The full Wind Resource Assessment (WRA) is complete and 

provides a much more detailed assessment of the wind resource than normally used in 

REO. A brief summary of the WRA for NAVSTA Newport is provided here. 

The key components of the WRA are:

• Coddington Point - Site #9202: 60 m met tower installed and operational at 

Coddington Point – July 29, 2009

• MiniSODAR unit installed and operational at Coddington Point – February 

22, 2010

• Tank Farm #4 - Site #9203: 60 m met tower installed and operational at Tank 

Farm #4 – March 19, 2010

The intent of the wind resource assessment activities is to attempt to characterize the 

wind resource for the entire base. Primary wind characteristics that can only be grossly 

estimated using wind maps, REO, or other available data are:

• Measured wind speed data at or close to sites where wind turbines will be 

erected correlated to long-term reference wind speeds 

• Vertical wind shear factor (VWSF) to determine wind speeds at hub height 

and through the entire rotor

• Wind frequency distribution (aka probability distribution function).

Wind Resource Assessment Activities at NAVSTA Newport

The wind assessment plan called for two fixed met tower stations at or near the northern 

and southern ends of the base that would be installed for at least one year. However, the 

base, being roughly six to seven miles north to south along a somewhat jagged coastline 

that includes some areas with hills rising quickly from the shore and some areas that are 

densely populated with one- to four-story buildings, is not easily characterized. See 

Figure A-1 for met tower locations. Different locations within the base will see somewhat 

different wind regimes due to topography and surface roughness. These two factors have 

different impacts in different seasons or times of the day depending on what direction the 

wind is coming from and its magnitude. The complexity of the site dictated that another 

dimension be added to the wind resource assessment campaign—the miniSODAR

system. 
59

Figure A-1. Map of NAVSTA Newport with met tower locations77

Sodar Systems

Sodar (sonic detection and ranging) systems are a relatively new technology being used 

to enhance (remote) wind resource measurement and characterization. They can be used 

to measure the vertical turbulence structure and the wind profile of the lower layer of the 

atmosphere at elevations suitable for wind turbines. Sodar systems operate by issuing an 

acoustic pulse that travels up into the air and reflects back a return signal as the sound 

bounces off of moisture or particulates moving in the air. Generally, both the intensity 

and the Doppler (frequency) shift of the return signal are analyzed to determine the wind 

speed, wind direction, and turbulent character of the atmosphere. A profile of the 

atmosphere as a function of height can be obtained by analyzing the return signal over a 

period of time following the transmission of each pulse. The return signal recorded at any 

particular delay time provides atmospheric data for a height that can be calculated based 

on the speed of sound. MiniSODAR systems, such as the one used at NAVSTA Newport, 

can effectively characterize the wind up to 150–200 m in the air. 

 77 DNV Renewables (USA) Inc. “Wind Resource Data Summary.” Naval Station Newport, Rhode Island, Data 

Summary and Transmittal, August 2010. 
60

The miniSODAR system, after initial calibration, alongside the 60 m met tower at 

Coddington Point, was to be moved to potential wind turbine sites on base every few 

months. It is known that the wind speed will vary widely at locations close to the ground 

throughout NAVSTA Newport. At some point above the ground (approximately 300 m, 

for instance), the wind speed will generally be similar at any location above the base. 

What is not known is at what height above ground all the potential turbine locations are 

essentially similar and how different the potential sites are at typical wind turbine rotor 

heights. The latter is of primary interest as it will determine the economic performance of 

wind turbines at the potential sites on base. 

The goal in the periodic movement of the sodar was to be able to characterize the wind 

speed, turbulence, wind direction, and VWSF at each site to determine the best sites for 

wind turbines at NAVSTA Newport. A detailed analysis of the sodar data is outside the 

scope of this analysis; however, it should be noted that the data aligns well with that 

collected at the Coddington Point 60 m met tower. The data will be used in a longer-term 

analysis to determine and rank the best sites for wind turbines at NAVSTA Newport 

based on the extent of the wind resource. There has not been enough data collected at 

enough sites to date to make that determination.

Analysis of Collected Wind Data at Coddington Point and Tank Farm #4

A 60 m met tower was erected/commissioned at Coddington Point in July 2009. A 

second 60 m met tower, configured similarly, was erected at Tank Farm #4 in March 

2010. NREL loaned a Wind ExplorerTM miniSODAR unit to NAVSTA Newport in 

March 2010. Combined, these three data collection devices were used to assess the wind 

resource at NAVSTA Newport. The analysis here will be brief and focused on the 

characterization of each site and the differences in wind speed pertaining to how they will 

effect wind turbine annual energy production and economics. A more thorough analysis 

of the wind at each site will be provided to NAVSTA Newport as part of the wind 

resource assessment per prior agreement with NFESC.
61

Wind Data at Coddington Point—Site # 9202

The configuration of the sensors can be seen in Table A-1.

Table A-1. Sensor Configuration at Coddington Point (Site #9202)

The sensor configuration at Tank Farm #4 was essentially the same.

The measurement characterizations for Coddington Point and Tank Farm #4 can be seen 

in Table A-2. To date, there are 19 months of collected data at Coddington Point and 12 

months worth of data collected at Tank Farm #4. 

Table A-2. Dataset Summary for Coddington Point and Tank Farm #4

Sensor Quantity Nominal Sensor 

Height (m)

Actual Sensor 

Height (m)

Sensor 

Orientation (°)

Boom 

Length (m)

NRG #40C Anem. 2 60 58, 58 274, 187 2.4, 2.4

NRG #40C Anem. 1 50 47.5 275 2.4

NRG #40C Anem. 2 40 40, 40 270, 188 2.4, 2.4

NRG #40C Anem. 1 25 24 270 2.4

NRG #200P Vane 2 50, 30 49, 26 3, 1 2.4, 2.4

NRG #110S Temp. 1 3 - - -

Voltmeter 1 - - - -

Coddington Point Tank Farm #4

Variable Value Variable Value

Latitude N 41.5194 Latitude N 41.56358

Longitude W 71.3273 Longitude W 71.29185

Elevation 5 m Elevation 29 m

Start Date 7/29/2009 Start Date 3/19/2010

End Date 3/13/2011 End Date 3/13/2011

Duration 20.5 months Duration 11.9 months

Length of Time Step 10 minutes Length of Time Step 10 minutes

Calm Threshold 3 m/s Calm Threshold 3 m/s

Mean Temperature 10.8 °C Mean Temperature 11.6 °C

Mean Pressure 101.2 kPa Mean Pressure 100.9 kPa

Mean Air Density 1.243 kg/m3 Mean Air Density 1.236 kg/m3

Power Density at 50 m 290 W/m2 Power Density at 50 m 238 W/m2

Wind Power Class 2 Wind Power Class 2

Power Law Exponent 0.147 Power Law Exponent 0.381

Surface Roughness 0.0607 m Surface Roughness 2.64 m

Roughness Class 1.59 Roughness Class 4.72

Roughness Description Rough pasture Roughness Description Urban
62

Table A-3 and Table A-4 highlight statistics of the collected data—first for Coddington 

Point, and then for Tank Farm #4. Coddington Point had a raw data recovery rate greater 

than 98.4% for all channels before filtering. Tank Farm #4 had a raw data recovery rate 

greater than 98.4% for all channels before filtering. The data recovery rates shown in the 

tables are the net recovery rates after filtering to remove unreliable data due to icing and

tower shading, for example. 

As shown, the mean wind speed at 58 m is approximately 0.34–0.51 m/s higher at 

Coddington Point than at Tank Farm #4. This difference is more pronounced at 24 m 

where Coddington Point is approximately 1.47 m/s higher. The difference in wind speed 

between Coddington Point and Tank Farm #4 is due to the nice “fetch” across the 

water—low surface roughness and few impediments to wind flow—which Coddington 

Point has relative to Tank Farm #4. At Tank Farm #4, there is significant ground clutter 

(trees, shrubs, and grass) and terrain factors (undulating hills sloping up from the 

Narragansett Bay) that cause turbulence and reduce overall wind speeds.

Table A-3. Wind Speed Sensor Summary at Coddington Point

Coddington Point

Variable

Speed 

58 m A

Speed 

58 m B

Speed 

47.5 m

Speed 

40 m A

Speed 

40 m B

Speed 

24 m

Measurement Height (m) 58 58 47 40 40 24

Mean Wind Speed (m/s) 6.647 6.447 6.407 6.274 6.208 5.872

Mean of Monthly Means Wind Speed (m/s) 6.516 6.348 6.264 6.139 6.099 5.731

Median Wind Speed (m/s) 6.3 6.1 6.1 5.9 5.9 5.5

Minimum Wind Speed (m/s) 0.4 0.4 0.4 0.4 0.4 0.4

Maximum Wind Speed (m/s) 24 23.5 23.2 23 22.8 22.3

Weibull k 2.031 2.039 1.957 1.957 1.972 1.885

Weibull c (m/s) 7.483 7.252 7.197 7.05 6.978 6.591

Mean Power Density (W/m2) 336 303 308 290 278 246

Mean of Monthly Means Power Density (W/m2) 318 290 289 273 266 230

Mean Energy Content (kWh/m2/yr) 2,940 2,653 2,694 2,537 2,438 2,156

Mean of Monthly Means Energy Content (kWh/m2/yr) 2,782 2,543 2,532 2,390 2,327 2,015

Energy Pattern Factor 1.868 1.847 1.911 1.917 1.901 1.987

Frequency of Calms (%) 13.45 14.22 15.39 16.09 16.25 19.49

Possible Records 85,248 85,248 85,248 85,248 85,248 85,248

Valid Records 81,556 70,674 83,922 81,689 74,845 83,922

Missing Records after Filtering 3,692 14,574 1326 3,559 10,403 1326

Data Recovery Rate (%) 95.67 82.9 98.44 95.83 87.8 98.44
63

Table A-4. Wind Speed Sensor Summary at Tank Farm #4

The mean diurnal profile (hourly averages throughout the day) of each site can be seen in 

Figure A-2 and Figure A-3. On average throughout the year, the wind picks up velocity 

during the late morning and continues throughout the day with the peak coming midafternoon, which is often a peak loading time for the utility. Though the patterns are the 

same, the wind speeds vary considerably. The difference between the wind speed at 24 m 

versus 58 m at Coddington Point varies by approximately 0.6–1.0 m/s (at different times 

of the day) due to the nice “fetch” across the water—that is, low surface roughness and 

few impediments to wind flow—whereas the variation is approximately 1.5–2.2 m/s at 

Tank Farm #4. This is due to the ground clutter and terrain factors.

Tank Farm #4

Variable

Speed 

58 m A

Speed 

58 m B

Speed 

47.5 m

Speed 

40 m A

Speed 

40 m B

Speed 

24 m

Measurement Height (m) 58 58 50 40 40 25

Mean Wind Speed (m/s) 6.141 6.109 5.813 5.387 5.45 4.407

Mean of Monthly Means Wind Speed (m/s) 6.141 6.109 5.813 5.387 5.45 4.407

Median Wind Speed (m/s) 5.7 5.7 5.4 5 5 4.1

Minimum Wind Speed (m/s) 0.4 0.4 0.4 0.4 0.4 0.4

Maximum Wind Speed (m/s) 22.6 22.4 21.9 20.7 20.4 17

Weibull k 2.014 2.007 1.949 1.891 1.969 1.839

Weibull c (m/s) 6.917 6.875 6.539 6.049 6.138 4.957

Mean Power Density (W/m2) 273 268 239 195 196 112

Mean of Monthly Means Power Density (W/m2) 273 268 239 195 196 112

Mean Energy Content (kWh/m2/yr) 2,393 2,352 2,089 1,708 1,720 977

Mean of Monthly Means Energy Content (kWh/m2/yr) 2,393 2,352 2,089 1,708 1,720 977

Energy Pattern Factor 1.887 1.884 1.941 1.992 1.938 2.078

Frequency of Calms (%) 16.1 15.85 18.5 21.83 20.46 33.11

Possible Records 51,696 51,696 51,696 51,696 51,696 51,696

Valid Records 50,027 47,049 51,420 49,808 46,712 51,420

Missing Records after Filtering 1,669 4,647 276 1,888 4,984 276

Data Recovery Rate (%) 96.77 91.01 99.47 96.35 90.36 99.47
64 

Figure A-2. Coddington Point—Diurnal wind profile 

Figure A-3. Tank farm #4—Diurnal wind profile 

The wind speeds at 58 m at the two sites vary considerably. Again, Coddington Point gets 

good fetch off the water with low ground clutter and higher wind speeds overall. 

Other variations between the two sites can be seen in the monthly box plots in Figure A-4 

and Figure A-5. The higher wind speeds are relatively similar between the sites, but the 

mean wind speeds and low wind speeds vary considerably. Also, the daily range of wind 

speeds is larger at Tank Farm #4. 

0 6 12 18 24

0

2

4

6

8

Mean Wind Speed (m/s)

Coddington Point - Mean Diurnal Profile

Hour of Day

Speed 58 A

Speed 58 B

Speed 47.5 m

Speed 40 A

Speed 40 B

Speed 24

0 6 12 18 24

0

1

2

3

4

5

6

7

Mean Wind Speed (m/s)

Tank Farm #4 - Mean Diurnal Profile

Hour of Day

Speed 58 m A

Speed 58 m B

Speed 50 m

Speed 40 m A

Speed 40 m B

Speed 25 m
65 

Figure A-4. Coddington Point boxplot 

Figure A-5. Tank Farm #4 boxplot 

The probability distribution function (aka frequency distribution) for Coddington Point 

can be seen in Figure A-6. 

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Ann

0

5

10

15

20

25

Value (m/s)

Coddington Point - Monthly Statistics for Speed 58 A

Speed 58 A

max

daily high

mean

daily low

min

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Ann

0

5

10

15

20

25

Value (m/s)

Tank Farm #4 - Monthly Statistics for Speed 58 m A

Speed 58 m A

max

daily high

mean

daily low

min
66 

Figure A-6. Overall frequency distribution at Coddington Point 

The probability distribution function for Tank Farm #4 can be seen in Figure A-7. 

Figure A-7. Overall frequency distribution at Tank Farm #4 

0 5 10 15 20 25

0

2

4

6

8

10

12

14

Frequency (%)

Coddington Point - Probability Distribution Function

Speed 58 A (m/s)

Actual data Best-fit Weibull distribution (k=2.03, c=7.48 m/s)

0 5 10 15 20 25

0

2

4

6

8

10

12

14

Frequency (%)

Tank Farm #4 - Probability Distribution Function

Speed 58 m A (m/s)

Actual data Best-fit Weibull distribution (k=2.01, c=6.92 m/s)
67 

The turbulence intensity for both sites is shown in Figure A-8 and Figure A-9. 

Figure A-8. Turbulence intensity at Coddington Point 

Figure A-9. Turbulence intensity at Tank Farm #4 

0 5 10 15 20 25

0.1

0.2

0.3

0.4

0.5

0.6

0.7

Turbulence Intensity

Coddington Point - Turbulence Intensity at 58 m

Wind Speed (m/s)

Representative TI

IEC Category A

IEC Category B

IEC Category C

Quantity Value

Records in 15 m/s bin 785

Mean TI at 15 m/s 0.101

Representative TI at 15 m/s 0.136

IEC3 turbulence category C

0 5 10 15 20 25

0.1

0.2

0.3

0.4

0.5

0.6

0.7

Turbulence Intensity

Tank Farm #4 - Turbulence Intensity at 58 m

Wind Speed (m/s)

Representative TI

IEC Category A

IEC Category B

IEC Category C

Quantity Value

Records in 15 m/s bin 301

Mean TI at 15 m/s 0.124

Representative TI at 15 m/s 0.169

IEC3 turbulence category B
68 

In Figure A-10, the wind rose for each site shows the total energy by direction. Also 

noteworthy is how the trees and hills to the north of Tank Farm #4 reduce the relative 

wind energy from that direction compared to the more open fetch at Coddington Point. 

Figure A-10. Wind rose—Total energy by direction at Coddington Point and Tank Farm #4 

The monthly wind roses at Coddington Point in Figure A-11 provide a better view of how 

the wind direction changes through the year and what directions and months provided the 

greatest wind energy. 

Figure A-11. Monthly wind roses—Total energy by direction at Coddington Point 

Coddington Point - Total Wind Energy (58 m)

0°

22.5°

45°

67.5°

90°

112.5°

135°

157.5°

180°

202.5°

225°

247.5°

270°

292.5°

315°

337.5°

6%

12%

18%

Tank Farm #4 - Total Wind Energy (58 m)

0°

22.5°

45°

67.5°

90°

112.5°

135°

157.5°

180°

202.5°

225°

247.5°

270°

292.5°

315°

337.5°

6%

12%

18%
69 

The monthly wind roses at Tank Farm #4 in Figure A-12 provide a better view of how 

the wind direction changes through the year and what directions and months provided the 

greatest wind energy. 

Figure A-12 Monthly wind roses—Total energy by direction at Tank Farm #4 

Relationship of Collected Data to Long-Term Data 

Normal industry wind resource assessment practice calls for collecting wind and other 

data as close to the proposed wind turbine site as possible and as close to the proposed 

wind turbine hub height as possible for a minimum of 1 year, providing a suitable longterm reference wind station can be found. Not every long-term reference station provides 

an adequate correlation factor, especially if there are significant data gaps or 

measurement intervals are different. 

With 12 months of quality, on-site data, the long-term reference station is used to 

“normalize” the collected data to approximate the expected long-term wind resource at 

the site. This normalization is accomplished through an analytic mathematical technique 

called “Measure-Correlate-Predict” (MCP). The data collected at Coddington Point and 

at the Newport Airport are the “measure” component. The sites can be seen in the map in 

Figure A-13. 
70 

Figure A-13. Coddington Point and Newport Airport met tower sites78

The long-term reference station used was a 10 m met tower at the Newport State Airport, 

which is approximately 2.5 miles from the 60 m met tower at Coddington Point. The 

Newport Airport is about 2.2 miles from the Tank Farm #4 met tower. The airport data, 

identified as Automated Airport Weather Station (AWOS) KUUU Newport, was 

obtained from the Utah State University Climate Center.79 The best available data from 

this station was a 5-year period from October 1, 2005, through October 1, 2010. 

Generally, longer-term data in the 10–15 year range is preferred as the wind resource is 

often difficult to fully characterize from a 5-year data source. 

Invalid data was flagged and a correlation analysis was run between the data from these 

two met towers for the concurrent period of August 1, 2009 through September 30, 2010. 

As shown in Figure A-14, the wind speeds from 10 m from Newport Airport were then 

plotted against wind speeds from 24 m at Coddington Point and a linear regression 

analysis (first-order polynomial) conducted to determine the trendline with resulting 

equation and r

2

 (coefficient of determination) correlation factor for each direction sector. 

The linear regression equation, in the form of “y = mx + b” enables the prediction of wind 

speeds at Coddington Point over a longer time scale using the long-term averaged data at 

 

78 DNV Global Energy Concepts, Inc. “Wind Resource Data Summary.” Naval Station Newport, Rhode Island, Data 

Summary and Transmittal, November 2009. 

79 Utah State University. “Climate Center: Data Products.” http://climate.usurf.usu.edu/products/data.php?tab=awos. 

Accessed October 5, 2011. 

Coddington Point #9202

Newport State Airport -

Long Term Reference
71 

the Newport Airport. The same process was applied to Tank Farm #4. The resultant 

equations are: 

Figure A-14. Correlation of concurrent Newport airport data to Coddington Point 

With the relationship between the Newport Airport and Coddington Point wind data 

established, the correlation equation was then applied to the Newport Airport data from 

January 14, 1999, to February 27, 2011, to establish the “long-term profile” of the wind 

speed at 24 m at Coddington Point. The VWSF from the collected data at Coddington 

Point between 24 m and 40 m was then applied to get the estimated long-term wind 

profile at 40 m at Coddington Point. The same process was applied to the VWSF from 40 

m to 47.5 m, and then from 47.5 m to 58 m, to establish a long-term dataset for 

Coddington Point up through the height of the met tower located there. 

 

Coddington Point 

Y = mx + b r2

Y = 1.037 2.0858 0.6645

Tank Farm #4

Y = mx + b r2

Y = 0.85153 1.4077 0.6707

0 510 15 20

0

5

10

15

20

25

Coddington Point 24 m WS (m/s)

Wind Speed Correlation - Coddington Point at 24 m vs. Newport Airport at 10 m

Newport Airport 10 m WS (m/s)
72 

Figure A-15 compares, on a long-term basis, the mean wind speeds at Coddington Point 

to Tank Farm #4 at two heights. As shown, the wind speeds at 24 m at Coddington Point 

are greater (by a small margin) than the expected wind speeds at 80 m at Tank Farm #4. 

The greater exposure to the wind off of the waters of Narragansett Bay coupled with low 

surface roughness in the south-west-north arc result in higher wind speeds and wind 

power density at Coddington Point. 

Figure A-15. Long-term wind profiles at Coddington Point and Tank Farm #4 

The VWSF from the collected SODAR data at Coddington Point was applied in 10 m 

increments resulting in a profile of the wind speed up to 120 m at Coddington Point. The 

results of the shearing up to 120 m can be seen in the diurnal wind profile shown in 

Figure A-16. This represents a 12-year profile. 

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

3

4

5

6

7

8

 Wind Speed (m/s)

Coddington Point vs Tank Farm #4 Long Term Wind Speed

Year

Cod Pt 24 m WS MCP

Cod Pt Synthesized 80 m

Tank #4 WS at 24m

Tank #4 Synthesized 80 m
73 

Figure A-16. Mean diurnal profile of Coddington Point 

This same process was applied between the Newport Airport data and the collected data 

at Tank Farm #4. The same vertical wind shear profile from the SODAR at Coddington 

Point was applied as the best available data at the time of the analysis. The results can be 

seen in Figure A-17. The same process can be reapplied with a vertical wind shear profile 

from SODAR from a site closer to Tank Farm #4. 

Figure A-17. Mean diurnal profile of Coddington Point 

0 6 12 18 24

0

2

4

6

8

10

Mean Wind Speed (m/s)

Coddington Point - Mean Diurnal Profile

Hour of Day

Synthesized 120 m

Synthesized 110 m

Synthesized 100 m

Synthesized 90 m

Synthesized 80 m

Synthesized 70 m

Synthesized 58 m

Synthesized 47.5m

Synthesized 40 m

MCP WS at 24 m

0 6 12 18 24

0

1

2

3

4

5

6

7

Mean Wind Speed (m/s)

Tank Farm #4 - Mean Diurnal Profile

Hour of Day

Synthesized 120 m

Synthesized 110 m

Synthesized 100 m

Synthesized 90 m

Synthesized 80 m

Synthesized 70 m

Synthesized 60 m

Synthesized 50 m

Synthesized 44 m

MCP WS at 24 m
74

Wind Turbine Energy Production

The normalized long-term wind data was used to estimate the annual energy production 

of a number of utility-scale wind turbines to serve as a reference of what may be possible 

to frame the scale of production and the relative economics. The results are not intended 

to be used to determine what turbine should be purchased. NAVSTA Newport has 

applied to the Federal Aviation Administration (FAA) for wind turbine installation 

approval, and the preliminary response indicated that the tip of the blade could be no 

higher than 500 ft (152 m) above mean sea level.

80

Table A-5. Turbine Power, Class, and Dimension 

The turbine height may vary at each 

particular site due to this factor. All of these turbines meet this criterion, as shown in 

Table A-5. 

Table A-6. Height Tolerance for Potential Wind Turbine Sites

Other sites may have to use a short tower or smaller rotor to meet Federal Aviation 

Administration (FAA) requirements. 

 80 Reichert, J. Email. NAVSTA Newport, Newport, RI, 19 May 2010.

Turbine Model

Power 

Rating

Stated 

Turbine Class

Hub 

Height

Rotor 

Span

Max 

Height

Max 

Height

# Turbines 

for 9 MW

MW Class m m m ft #

Siemens 2.3 MW 101 2.3 III 80 101 130.5 428 3.9

GE 1.5 XLE 1.5 III 80 82.5 121.25 398 9

RePower MM92 2.0 III 80 92 126 413 4.5

Vestas V90 1.8 MW 1.8 III 80 90 125 410 5

Clipper Liberty C101 2.5 III 80 101 130.5 428 3.6

Nordex N100 2.5 III 80 100 130 427 3.6

Site

Site 

Elevations

Max 

Turbine 

Height

Siemens 

2.3 MW 

101

GE 1.6 

XLE

RePower 

MM92

Vestas 

V90 1.8 

MW

Clipper 

Liberty 

C101

Nordex 

N100

m ASL* m m m m m m m 

Coddington Point 7 145.4 130.5 121.25 126 125 130.5 130

Tank Farm 1 30 122.4 130.5 121.25 126 125 130.5 130

Tank Farm 2 50 102.4 130.5 121.25 126 125 130.5 130

Tank Farm 3 30 122.4 130.5 121.25 126 125 130.5 130

Tank Farm 4 30 122.4 130.5 121.25 126 125 130.5 130

Tank Farm 5 30 122.4 130.5 121.25 126 125 130.5 130

McAllister Point 10 142.4 130.5 121.25 126 125 130.5 130

Gould Island 21 131.4 130.5 121.25 126 125 130.5 130

Directors Shipyard 10 142.4 130.5 121.25 126 125 130.5 130

Coddington Cove 15 137.4 130.5 121.25 126 125 130.5 130

Helipad 5 147.4 130.5 121.25 126 125 130.5 130

Note: * ASL = Above Surface Level

Note: Color code Outside tolerance limit

Within tolerance limit
75

In Table A-7 and Table A-8, the estimated output per wind turbine at each site is shown. 

The hub height wind speed variation is the driving force behind the output variation. 

There may be a small degree of turbine parameter adjustment that can provide slight 

improvements to overall annual energy production, but these factors will vary site by site 

and will need to be optimized once the wind flow characteristics of the entire site have 

been modeled.

Table A-7. Coddington Point Wind Turbine Annual Energy Production

Table A-8. Tank Farm #4 Wind Turbine Annual Energy Production

There are many factors involved in choosing a wind turbine for NAVSTA Newport. It 

would be beneficial to collect more data, determine the number of sites that can support a 

wind turbine both economically and through permitting, and then issue a request for 

proposals (RFP) and determine the best option based on the responses from qualified 

contractors. For this report, the economics will be based on a single turbine located at 

Coddington Point and purchased through an Energy Conservation and Investment 

Program (ECIP) grant, so there will be no financing fees. 

Economic Assumptions for the Wind Analysis 

Project Life

The project life is assumed to be 20 years. Wind turbine design life is typically at least 20 

years. The wind turbine useful life is estimated to be 20–30 years. This generation of 

1+ MW turbines is not yet 20 years old so there is no actual field experience to point 

towards in suggesting another basis. 

Wind Turbine Cost 

An average turbine cost of $3.80/kW of installed capacity was used to approximate the 

cost of several commercial wind turbines. NAVSTA Newport has initial plans to 

purchase 9 MW of wind at a cost of approximately $34.2 million. Industry averages, 

Hub 

Height

Hub Height 

Wind Speed

Time At 

Zero Output

Time At 

Rated Output

Mean Net 

Power Output

Mean Net 

Energy Output

Capacity 

Factor

Turbine (m) (m/s) (%) (%) (kW) (kWh/yr) (%)

Siemens SWT-2.3-101 80 7.16 11 3.7 771.2 6,756,085 33.5

GE 1.5xle 80 7.16 0 5.7 462.8 4,053,887 30.9

REpower MM92 80 7.16 11 7.4 700.1 6,133,311 35.0

Vestas V90 - 1.8 MW 80 7.16 11 3.8 601.3 5,267,641 33.4

Clipper Liberty C99 80 7.16 11 3.7 760.7 6,664,157 30.4

Nordex N90/2500 LS 80 7.16 11 1.3 688.9 6,034,679 27.6

Hub 

Height

Hub Height 

Wind Speed

Time At 

Zero Output

Time At 

Rated Output

Mean Net 

Power Output

Mean Net 

Energy Output

Capacity 

Factor

Turbine (m) (m/s) (%) (%) (kW) (kWh/yr) (%)

Siemens SWT-2.3-101 80 5.62 21 2.9 522.0 4,573,080 22.7

GE 1.5xle 80 5.62 11 4.4 314.3 2,753,158 21.0

REpower MM92 80 5.62 26 5.5 470.8 4,124,429 23.5

Vestas V90 - 1.8 MW 80 5.62 21 3.0 401.7 3,518,894 22.3

Clipper Liberty C99 80 5.62 21 2.9 513.7 4,499,855 20.5

Nordex N100/2500 80 5.62 21 2.8 529.5 4,638,293 21.2
76

based on wind farms of 50–500 MW, do not apply when installing a small number of 

turbines as NAVSTA Newport will. The average size of the turbines modeled was 

2.1 MW. This cost is not necessarily representative of individual turbine prices, but these 

costs vary depending on a variety of factors (e.g., the economy, turbine/contractor 

availability, currency fluctuations, and part of the country). RFP responses are the best 

method to get truly realistic cost figures for particular turbines.

Annual Energy Output

The “average” turbine for Coddington Point was scaled based on average output for all 

the modeled turbines and average power rating of these turbines to arrive at a megawatthour per year output per megawatt (2,770,000 MWh/yr/MW). Due to the lower wind 

speeds at Tank Farm #4, the same approach yielded a rating of 1,913,000 MWh/yr/MW. 

It was assumed only one turbine would approach the productivity of Coddington Point—

the one sited there. All other wind turbines needed to reach approximately 9 MW would 

perform in lower wind speeds and have lower outputs. It was assumed that Tank Farm #4 

represents an “average” wind site among the potential sites identified by NAVSTA 

Newport. Of course, additional wind modeling will need to be done to determine if this 

was a reasonable assumption. To reach NAVSTA Newport’s RE goal of 25% generated 

on-site, it was estimated that another 5.5 MW of wind will need to be installed. In 

estimating this figure, it was assumed that subsequent sites would have lower annual 

energy output than Tank Farm #4. An estimate of 1,700,000 MWh/yr/MW was used for 

these calculations. Again, additional wind modeling will need to be done to determine if 

this is a reasonable assumption.

Operations and Maintenance

O&M costs are assumed to average $21/MWh over the life of the project, and the 

gearbox will need to be replaced after 10 years of operation.81 This cost may seem 

comparatively high, but several factors combine to give a high level of uncertainty. First, 

there is reason to believe that larger turbines may have a small economy of scale on 

O&M costs, as tens of thousands of megawatts of wind continue to be installed in the 

near term, serving to drive this cost down. There are substantial research and 

development investments currently being made by both the private and public sector 

aimed at reducing O&M costs. However, several internal NREL studies82

Salvage Value

have shown 

that various component failures, such as gearbox failure, will drive this cost up on 

average for this generation of turbines. In summary, there is speculation and uncertainty

as to how the average cost of O&M should be modeled for utility-scale turbines, 

especially in small projects such as this.

The expected salvage value of the wind turbine, which has a significant number of 

components made of steel, copper, and other useful materials, is expected to have enough 

residual value to cover the demolition costs. In many sites that have smaller, older wind 

 81 Wiser, R.; Bolinger, M. “Wind Technologies Market Report.” DOE, EERE, 2009, p.54. 82 Oyague, F.; Butterfield, C.P.; Sheng, S. “Gearbox Reliability Collaborative Analysis.” Round Robin, WINDPOWER 

2009 Conference.
77

turbines, 15–20 years old, a process called repowering is taking place, in which the 

existing turbine nearing the end of its useful life is replaced with a newer, sometimes 

larger, turbine because the permitting, electrical, and other issues have already been 

addressed. Full turbine/foundation demolition and site restoration are not common.

Escrow Unscheduled Maintenance Repair Fund

During the 20-year life of a wind turbine project, it is expected that a turbine will have 

need for a major repair at a significant cost in the hundreds of thousands of dollars range. 

If the project were financed through an energy savings performance contract (ESPC), 

utility energy savings contract (UESC), or even a power purchase agreement scenario, it 

is assumed that embedded in the price, NAVSTA Newport would pay for the renewable 

electricity output of the turbine, and there would be an additional amount set aside by the 

project operator to fund a major repair when the need arises. It is also possible that the 

contract could specify an escrow fee, independent of the price paid for electricity, for 

unscheduled repairs.

In the scenario in which NAVSTA Newport owns the turbine as a result of a cash 

purchase, it is highly recommended that it institutes a self-funded mechanism, such as an 

escrow account, to fund a reserve account to be tapped when the need for a major repair 

arises. The purpose of the escrow account would be to cover capital repairs, such as blade 

failure and gearbox failure, to ensure smooth, continuous operation with minimal 

downtime in the event of catastrophic equipment failure. Though it is not possible to 

predict exactly when these types of repairs will be necessary, having this fund ready will 

enable NAVSTA Newport to have repairs taken care of quickly, as there will be no need 

to search for funds to pay for them. The funding and expense stream are not possible to 

match, but the escrow fund should prepare NAVSTA Newport to meet any capital repair 

expenses that arise.

Economic Projections of a 2.0 MW Wind Turbine at Coddington Point

These costs were modeled using RETScreen Wind software83

The results of the modeling can be seen in Table A-9.

with the wind resource data 

from the normalized Coddington Point dataset.

 83 RETScreen International, Natural Resources Canada. http://www.retscreen.net/ang/home.php. Accessed October 5, 

2011. 
78

Table A-9. Economics of Generic 2.0 MW Wind Turbine at Coddington Point

The recorded wind speeds at Coddington Point have been shown to support a solid 

project on economic ground assuming that ECIP funding is available, the project would 

essentially involve a cash purchase with no financing costs, and the annual O&M would 

be paid for out of cost savings.

Given NAVSTA Newport’s RE goals, it makes sense to fully explore a multiple wind 

turbine project. A more complete assessment that includes all of the potential wind 

turbine sites, as planned, is the recommended course of action. As shown by the data at 

Coddington Point and Tank Farm #4, there is a significant level of variability in the wind 

resource at these two sites. It is expected there will be at least that level of variability, 

possibly more at several of the other potential sites. With a more complete dataset from 

across the entire base, a more thorough economic analysis can be completed.

Characteristic Measurement Units

Wind Turbine Swept Area 19,085 m2

Wind Turbine Swept Area 205,429 ft2

Wind Capacity 9,000 kW

Wind Initial Cost 34,200,000 $

Wind Rebate - $

Wind Production Incentive - $/yr

Wind State Tax Credit - $

Wind Federal Tax Credit 10,260,000 $

Wind Initial Cost w/ Incentives 23,940,000 $

Wind Net Metering Limit (Up To) 1,650 kW

Wind Annual Energy Delivery 23,843,000 kWh/yr

Capacity Factor 30.2 %

Wind Annual Cost Savings 2,861,160 $

Wind Annual O&M Cost 71,100 $/yr

Wind Payback Period 8.6 yrs
79

Appendix B. Solar Vent Preheat Systems

Solar Vent Preheat System Sizing

For a given amount of ventilation air, the suggested size is given by the equation

Ac = Vbldg/vwall

where

Ac = solar collector area (ft2or m

2

); might be limited by available wall area

Vbldg = building outside air flow rate (CFM or l/min)

vwall = per-unit-area airflow through wall (CFM/ft2 or l/min/m2); typically 4–8 

CFM/ft2

. If wall area is sufficient, use the lower value of 4 CFM/ft2.

The size of the south-facing wall is a constraint. A size that results in a flow rate of less 

than 2 CFM/ft2 is also a constraint, so that the boundary-layer effect that leads to the high 

efficiency is valid. 

Energy delivered by the SVP system and fuel energy saved are calculated by the 

equations

Qsolar = Ac quseful × (#days/week/7)/ ηheating

and

Qsaved = Qsolar/ηheating

where

Qsolar = annual heat delivery of solar system (kWh/yr or MBtu/yr)

Qsaved = annual fuel energy saved (kWh/yr)

ηheating = heating system efficiency

Additional fan power required to pull the ventilation air through the SVP system is 

calculated by the equation

Qfan = Ac

qfan × (#hours/day × #days/week × #weeks/year)

where

qfan = fan energy required to pull air through the collector (taken to be 1 W/ft2 for 

this analysis)
80

Figure B-1. Solar vent preheat cost curve

Credit: Andy Walker and Dan Olis, NREL

y = 1021.1x-0.403

R2 = 0.7899

$0

$20

$40

$60

$80

$100

$120

0 500 1000 1500 2000

Cost ($/ft^2)

Size (ft^2)

SVP Cost/ft2 vs Size

Cost/Size Data

Power (Cost/Size Data)
81

Appendix C. Solar Hot Water Systems 

Suggested size for the solar water heating system is estimated using the equation

where

Ac = collector area (m2) 

L = daily load (kWh/day)

ηsolar = efficiency of solar system (typically 0.429 for all locations from 

reference84

Imax = maximum daily solar radiation (kWh/m2/day)

)

Using Imax in the above equation means the system is designed to meet the load on the 

sunniest days of the year. This sizing strategy optimizes economic performance since 

there is no excess capacity. Annual energy savings (kWh/year) is estimated by the 

equation 

 

where

Iavg = average solar radiation (kWh/m2

/day)

ηboiler = auxiliary heater efficiency. Auxiliary water heater efficiency is taken85 for 

different types of water heaters: gas 0.43 to 0.86, assume 0.57; electric 0.77 to 

0.97, assume 0.88; heat pump, assume 2.0; propane 0.42 to 0.86, assume 0.57; oil 

0.51 to 0.66, assume 0.52. If fuel use was not provided, electricity was assumed to 

be used for water heating. 

 84 Christensen, C.; Barker, G. Annual System Efficiencies For Solar Water Heating. Golden CO: National Renewable 

Energy Laboratory.

85 Gas Appliance Manufacturer’s Association, http://www.gamanet.org/ . Accessed May 2009.

L

ηsolar x Imax

Ac =

Ac × Iavg×ηsolar × 365 

ηboiler

Es =
82

Solar system cost is estimated according to the formula

C = (csolar Ac-rebate) × (1 - federal tax credit) × (1 - state tax credit)

where

C = installed cost of solar system ($)

Csolar = per-unit-area cost of installed solar system ($/m2

), typically $400/m2 for 

large systems up to $1,200/m2 for small systems. The value used in this analysis is 

$73/ft2 ($800/m2

). Any incentives, in terms of percent-of-cost rebate or dollar-persquare-meter rebate are subtracted from the installed cost.

Annual cost savings are estimated by the equation

S = Es Ce - CO&M + Es × Cproduction incentive

where 

S = annual cost savings ($/year)

Ce = cost of auxiliary energy ($/kWh). 

Cproduction incentive = payments or credits for delivered energy ($/kWh). The COE is 

calculated for the water heating fuel type from use and cost data provided for each 

center.

Any other annual costs or revenues, such as O&M costs or production incentives, are 

added or subtracted from the annual cost savings.

Figure C-1. Solar hot water cost curve

Credit: Andy Walker and Dan Olis, NREL

y = 253.88x-0.116

R2 = 0.7887

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

$200

0 1,000 2,000 3,000 4,000 5,000 6,000

Cost per Squre Foot ($/ft2)

Area of Collector (ft2)

Solar Hot Water Cost vs. Area Curve

$/sqft

Power ($/sqft)
83

Appendix D. Photovoltaic Systems

The size of the PV system in kilowatts of rated output is determined by the optimization. 

In the equation below, note that units of I, solar radiation, are sun-hours per day. This unit 

has the same value as kilowatt-hours per square meter per day in the data because PV 

devices are rated at 1 kW/m2 radiation. Solar system size is: 

Prated = rated PV power (kW) 

Balance-of-system (BOS) efficiency is taken to be 77% to represent mismatch losses in 

the array and losses in the inverter and transformer. Annual electric energy savings are 

estimated as 

Es = 0.77 × Prated Iavg × 365 

where 

Iavg = average solar radiation (sun-hours/day or kWh/m2

/day)

PV system cost is estimated by the equation

C = (csolar Prated - rebate) × (1 - federal tax credit) × (1 - state tax credit)

where

C = installed cost of solar system ($)

csolar = per-unit cost of installed solar system, typically $5.10–$9.10/W. For this 

analysis we use the value $7.10/Watt-DC installed cost.

Annual cost savings are estimated by the equation

S = Es Ce – CO&M

where

S = annual cost savings ($/year)

Ce = cost of utility energy ($/kWh)

CO&M = annual cost of O&M, taken as 0.143% of installed cost.
84

Figure D-1. PV cost curve

Credit: Andy Walker and Dan Olis, NREL

y = 6.7637x-0.061

R2 = 0.4353

$-

$1 

$2 

$3 

$4 

$5 

$6 

$7 

$8 

$9 

0 500 1,000 1,500 2,000 2,500

PV Cost per Watt ($/W)

PV Collector Area (ft^2)

PV Cost per Watt vs. Area

Series1

Power (Series1)
85

Appendix E. Solar Industrial Process Heat and Solar 

Thermal Electric

The governing equations for sizing a concentrating solar system include:

Es, electric = Ac × Iavg × ηsolar × 365 × ηcogeneration

where

Iavg = average solar radiation (kWh/m2/day)

ηcogeneration = efficiency of the electric generator

ehx = effectiveness of the heat recovery heat exchanger 

ηboiler = auxiliary heater efficiency

Ac × Iavg×ηsolar × 365 × (1- ηcogeneration) × ehx

ηboiler

Es, gas =
86

Appendix F. Biomass Energy 

Biomass Resource Data 

Data on biomass resources available at NAVSTA Newport were taken from existing 

biomass resource inventory conducted by NREL in 2008and available at: 

http://www.nrel.gov/gis/data_biomass.html. No on-site biomass data was provided. 

Biomass resources considered from surrounding areas include: crop residues, forest 

residues, primary mill residues, secondary mill residues, urban wood waste, methane 

emissions from landfills, methane emissions from manure management, and methane 

emissions from domestic wastewater treatment. The data is by county, in dry tones/year 

for solid biomass and tonnes/year for the gaseous resources (methane). 

Crop Residues 

The following crops were included in this analysis: corn, wheat, soybeans, cotton, 

sorghum, barley, oats, rice, rye, canola, dry edible beans, dry edible peas, peanuts, 

potatoes, safflower, sunflower, sugarcane, and flaxseed. The quantities of crop residues 

that can be available in each county are estimated using total grain production, crop-toresidue ratio, and moisture content and take into consideration the amount of residue left 

on the field for soil protection, grazing, and other agricultural activities.

Forest Residues 

Forest residues are logging residues and other removable material left after carrying out 

silviculture operations and site conversions. Logging residue consists of unused portions 

of trees, cut or killed by logging, and left in the woods. Other removable materials are the 

unutilized volume of trees cut or killed during logging operations from.

Primary Mill Residues 

Primary mill residues include wood materials (coarse and fine) and bark generated at 

manufacturing plants (primary wood-using mills) when round wood products are 

processed into primary wood products, like slabs, edgings, trimmings, sawdust, veneer 

clippings and cores, and pulp screenings.

Secondary Mill Residues 

Secondary mill residues include wood scraps and sawdust from woodworking shops—

furniture factories, wood container and pallet mills, and wholesale lumberyards. 

Urban Wood Waste 

This analysis includes wood residues from municipal solid wastes, utility tree trimming 

and private tree companies, and construction and demolition sites. 

Methane Emissions from Landfills 

Three key factors were considered to evaluate the methane emissions from landfills: total 

waste in place, landfill size, and geographic location (arid or non-arid climate).
87

Methane Emissions from Manure Management 

The following animal types were included in this analysis: dairy cows, beef cows, hogs 

and pigs, sheep, chickens and layers, broilers, and turkeys. The methane emissions were 

calculated by animal type and manure management system.

Methane Emissions from Domestic Wastewater Treatment

The methane generation is estimated using methodology from the EPA86 and 2000 

population data from the U.S. Census Bureau87

System Sizing and Economics

.

A number of the indicative metrics for energy efficiency, equipment capital costs, and 

plant O&M costs were derived from industry figures and project costs assembled by 

Econergy,88 an NREL consultant. Other costs not accounted for in this analysis include 

development cost, land, enclosure buildings, and balance of plant.89

The primary equations and relationships include:

Es, gas = Cboiler × ηbiomass boiler × 8,760 × CFboiler (1 - ηcogeneration + (1 - η

Es, electric = Cboiler × ηbiomass boiler × 8,760 × CFboiler × ηcogeneration

cogeneration) × 

ehx/ηgasboiler

where

Cboiler = biomass boiler size (MBtu/h) = variable determined by the optimization

CFboiler = capacity factor (percent of time operational)

ηcogeneration = the efficiency of the electric generator

ehx = the effectiveness of the heat recovery heat exchanger 

ηboiler = auxiliary heater efficiency. 

Boiler heat delivery (therms) = boiler size × capacity factor

Biomass initial cost ($) = boiler size × cost per thousands of BTUs per hour 

(MBH) + electric Cogen size × kW of Cogen × city cost adjustment factor from 

RS Means cost estimating manuals

 86 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003, 

http://epa.gov/climatechange/emissions/downloads06/05CR.pdf. 87 U.S. Census Bureau. “2000 County Business Patterns.” http://www.census.gov/econ/cbp/. Accessed 

September 2005.

88 Emissions from Integrated MSW Strategies, http://www.p2pays.org/ref/11/10516/emissions.html. Accessed May 

2010.

89 NREL Biomass Plant Costs, Letter Report: Boulder, CO: Econergy International Agency. November 13, 2007. 

www.econergy.com. Accessed May 2010.
88

Biomass cogeneration size (kW) = variable determined by optimization 

Biomass gas savings (therms/year) = minimum of site gas use and thermal energy 

provided by boiler - that converted to electricity ÷ heat recovery steam generator 

effectiveness

Biomass electric delivery (kWh/year) = minimum of electric energy generation as 

calculated by Cogen capacity × capacity factor or as limited by boiler capacity, 

boiler efficiency, and boiler capacity factor

Biomass capacity factor = electric delivery ÷ Cogen capacity and 8,760 h/y

Biomass annual utility cost savings ($/year) = minimum of Cogen capacity or 

demand (kW) credited at retail rate + any generation in excess of that credited at 

avoided cost + federal production incentive × electric generation + gas savings ×

gas rate

Tons of fuel used = boiler heat delivered for both process heat and Cogen ÷ boiler 

efficiency ÷ heating value of fuel

Radius to collect fuel (miles) = radius calculated from area quotient of fuel 

required (tons) and density (tons/square mile)

Per ton fuel cost ($/ton) = fixed cost ($/ton) + trucking cost ($/ton/mile)

Fuel cost ($) = fuel used - fuel available onsite × fuel cost ($/ton)

State tax credit (%) = variable to be input by user

Federal tax credit (%) = variable to be input by user

Rebate ($) = variable to be input by user

Biomass cost with incentives ($) = boiler cost above - any rebates or tax credits

Biomass O&M cost ($/year) = $ per MBH of boiler capacity per year

Biomass payback period (years) = cost with incentives ÷ cost savings - O&M 

costs and - fuel costs.

Air Quality Concerns

Unlike the other RE technologies considered in this report, on-site use of biomass 

resources involves atmospheric emissions, solid waste residues (ash), and possibly waterborne wastes. While the decomposition of waste into simpler compounds by gasification 

should reduce emissions, detailed data for gasification could not be found in the literature 

(except for coal and clean wood). It may be expected, however, that emissions from a 

gasification operation could be no worse than those of a direct-burn operation, which may 
89

be found in the literature. The following values of pounds per ton for direct combustion 

of refuse-derived-fuel are from Emissions From Integrated MSW Strategies90

Table F-1. Selected Emissions Data for Each Biomass Conversion Considered

:

particulates 0.05; carbon monoxide (CO) 2.06; hydrocarbons 0.08; nitrogen oxide (NOx) 

2.64; methane 2.29; carbon dioxide (CO2) 1,460; water 970; non-methane organic 

compound (NMOC) 0.12; dioxin/furan 0.0038; sulfur 1.1; and hydrogen 0.26. Also, the 

following values are for the same publication for anaerobic digestion: particulates 0.02; 

CO 0.79; hydrocarbons 0.08; NOx 0.32; methane 14.34; CO2 437; water 188; NMOC 

0.75; and dioxin/furan, sulfur, and hydrogen are not applicable. In addition to these air 

emissions, ash from a gasifier using waste as fuel may contain metals that could leach out 

in a landfill, depending on the nature of the waste. Office paper, cardboard, and waste 

from convenience food operations have been found to be very uniform and free of metals, 

polyvinyl chloride (PVC), and other materials that may be of special concern.

Fuel CO2 emissions (kg/TJ) Nitrous Oxide (N2O)

emissions (kg/TJ)

Natural Gas 56,100 0.1

Wood 112,000 4.0

Biodiesel 70,800 0.6

Bio-gas 54,600 0.1

TJ = trillion joules91

Combustion Platform

Direct combustion of biomass to generate heat for steam production has been the most 

common application of biomass. It can also be used in a topping cycle for steam 

cogeneration of heat and power. Direct combustion systems utilize either a spreader 

stoker grate or fluidized bed in the combustion chamber. The overall costs and 

efficiencies of these approaches are similar and are not analyzed separately. The results 

apply to both. 

Configuration 1A Biomass Combustion/Steam Cycle

Biomass heat is provided by a boiler of a capacity determined as a result of the 

optimization. Cost and combustion efficiency of the boiler are specified. Some of the heat 

output of the boiler may be converted to electricity by a steam turbine in a cogeneration 

topping cycle. Boiler fuel may be wood chips or bio-oil. Bio-oil could be used by existing 

boilers and storage tanks with minimal modifications. 

Gasification Platform

Gasification is a high-temperature process that is optimized to produce a fuel gas with a 

minimum of liquids and solids. Gasification consists of heating the feed material in a 

 90 SRI International. “Emissions from Integrated MSW Strategies.” NREL Technical Report, NREL/TP-431-4988-A.

http://www.p2pays.org/ref/11/10516/emissions.html. Accessed May 2010. 91 Gomez, D., Watterson, J. “Volume 2: Energy Table 2.2 Default Emission Factors for Stationary Combustion in the 

Energy Industries (kg of greenhouse gas per TJ on a Net Calorific Basis).” http://www.ipccnggip.iges.or.jp/public/2006gl/pdf/2_Volume2/V2_2_Ch2_Stationary_Combustion.pdf. Accessed May 2005.
90

vessel with or without the addition of oxygen. Water may or may not be added. 

Decomposition reactions take place, and a mixture of hydrogen and CO are the 

predominant gas products, along with water, methane, and CO2.

Configuration 2A Biomass Gasification/Steam Cycle

Configuration 2A is a biomass gasification system that fuels a steam cycle. The system 

gasifies biomass and immediately burns the syngas in a heat-recovery steam generator 

(HRSG) to produce steam for the steam turbine. The combined gasification and boiler 

efficiency is about 64%. The steam-to-electricity conversion efficiency of a standard 

steam cycle is taken as 50% while heat can be recovered at about 80% effectiveness. 

O&M costs should be very similar to a conventional biomass fired boiler.

Configuration 2B Biomass Gasification/Spark Ignition Reciprocating Engine

Configuration 2B considers a slightly more advanced biomass gasification process called 

pyrolytic gasification whereby a high-British-thermal-unit content syngas is produced by 

externally heating biomass. The syngas generated in this process then has sufficient 

energy content to run spark-ignition reciprocating engines. Typically these engines are 

de-rated to account for the reduced energy content of the syngas when compared with 

natural gas. Hence the engine combined heat and power (CHP) costs on a dollar-perkilowatt basis are higher than for a natural gas system. The fuel-to-electricity conversion 

efficiency of a gas engine operating on syngas is roughly 37% based on lower heating 

value, and heat recovery effectiveness is typically around 80%. The O&M costs reflected 

here represent the O&M costs for the gasification plant and the gas engines, or roughly 

$18/MWh.

Configuration 2C Biomass Gasification/Combustion Turbine Combined Cycle

The last configuration considered for gasification systems is the combined cycle. This is 

the least commercialized configuration of the three systems and costs are, therefore, less 

certain. The gasification system cost has been assumed to be equal to Configuration 2B; 

however, it may actually require more gas-cleanup systems and could likely be higher. 

The combined-cycle cost is indicative of natural gas combined-cycle costs with a slight 

power output de-rating for the syngas. The same gasification efficiency has been assumed 

as for Configuration 2B, and the combined cycle will see a decreased efficiency relative 

to the natural gas baseline. However, future improvements in process design should be 

able to bring the efficiency up considerably. Heat recovery has been assumed at zero 

because the system would likely be at utility scale and would use a condensing steam 

turbine for maximum electrical generation. The system has a lower O&M cost compared 

to the gas engine configuration but higher O&M cost than the steam cycle. Future 

integrated gasification and combined cycle (IGCC) configurations utilizing pressurized 

oxygen-blown gasification have higher plant efficiencies than what is shown here.
91

Figure F-1. Platform 2B biomass gasification with syngas utilization via spark-ignition 

reciprocating engines

Credit: Jim Leyshon, NREL

Pyrolysis Platform

Configuration 3A Pyrolysis/Steam Cycle

Configuration 3A is fast pyrolysis followed by a conventional steam cycle. The 

efficiency of biomass pyrolysis to bio-oil is about 77%, while the boiler efficiency is

roughly 80%, resulting in a total efficiency of 61%. The cost for the pyrolysis plant is 

given in dollars per hourly million British thermal units of bio-oil production. The steamto-electricity conversion efficiency of a standard steam cycle is taken as 50% and heat 

recovery as 70%. O&M costs include the O&M for the steam cycle and the pyrolysis 

plant in terms of hourly million British thermal units of bio-oil utilization. 

Configuration 3B Pyrolysis/Compression Ignition Engine

The second pyrolysis configuration considers a fast-pyrolysis plant fueling modified 

compression ignition engines. This system has an advantage over 1B because liquidfueled compression-ignition engines have higher efficiencies. Published literature 

indicates that diesel engines burning bio-oil achieve comparable efficiencies to those 

using diesel fuels, although modifications to the fuel-handling system for preheating the 

bio-oil are required. Heat recovery effectiveness is assumed to be 80%.

Configuration 3C Pyrolysis/Combustion Turbine Combined Cycle

The final configuration for a fast-pyrolysis plant is to fire the bio-oil in a combustion 

turbine combined cycle. Research on the subject indicates that modified simple-cycle 

combustion turbines can easily reach 28% fuel-to-electricity conversion efficiency with 

an expected combined-cycle efficiency of 35%. However, they have been shown to 

operate at or above rated turbine power output; thus, the combined cycle is not de-rated 

and the cost is shown for a conventional natural gas combined cycle. It is likely that the 

first commercial system using this configuration will have much higher combined-cycle 
92

efficiencies, but this probably represents the current state of the art. As in Configuration 

2C, it is assumed that a bio-oil-fired combined cycle will not have heat recovery for 

district heating applications.

Anaerobic Digestion Platform

Configuration 4A Anaerobic Digestion/Spark Ignition Engine 

This configuration involves anaerobic digestion (AD) of mixed energy crops and manure,

which would be typical for farm-based applications in the 100–500 kW scale. These 

smaller-scale gas engines operating on digester gas are typically not de-rated as much as 

for syngas and have lower installed costs. The digester efficiency has been assumed to be 

57%, which is an average efficiency for different types of energy crop and manure 

feedstocks. The efficiency for AD systems is lower because they can only utilize the 

volatile solids content while the lignocellulosic material is removed and sold as fiber. The 

efficiency of smaller-scale gas engines is slightly lower at 35% compared to larger 

engines, while heat recovery is also less efficient. Plant capacity factors are dependant 

mainly on the AD systems, and 92% is the goal for many applications.

Configuration 4B Anaerobic Digestion/Microturbine

Microturbines can also be used with digester gas and offer a good fit at these small 

scales. These systems offer lower electrical efficiency but higher heat recovery because 

of the higher-temperature flue gases.

Configuration 4C Anaerobic Digestion/Molten Carbonate Fuel Cell 

The final configuration considers an anaerobic digester supplied by a molten carbonate 

fuel cell (MCFC). The MCFC is the only commercialized CHP fuel cell and has been 

proven on biogas. This configuration has the highest electrical efficiency but lower heat 

recovery efficiency because heat is consumed by the internal-reforming process of the 

fuel cell. Capacity factor for MCFC running on biogas has been observed at around 85% 

but can be expected to increase as their commercial use increases. This system is also the 

most expensive of the three platforms considered here but could qualify for incentives for 

both the AD system and the fuel cell.
93

Figure F-2. Platform 4A anaerobic digester and spark-ignition engine with heat recovery

Credit: Jim Leyshon, NREL
94 

Table F-2. Characteristics of Biomass Heat and Power Technologies92

 

Combustion with steam 

topping cycle cogeneration 

Biomass gasification with 

syngas utilization via 

conven-tional steam cycle 

Biomass gasification with 

syngas utilization via sparkignition reciprocating 

engines 

2C Biomass gasification with 

syngas utilization via 

combus-tion turbine 

combined cycle 

Biomass fast pyrolysis with 

bio-oil utilization via 

conventional steam cycle 

Biomass fast pyrolysis with 

bio-oil utilization via 

compression-ignition 

reciprocating engines 

Biomass fast pyrolysis with 

bio-oil utilization via 

combustion turbine 

combined cycle 

Anaerobic Digestion of 

biomass with biogas 

utilization via spark ignition 

reciprocating engines 

Gasifier/Boiler/Digester Cost ($/MBH) 500,000 195,802 195,802 195,802 223,590 223,590 223,590 419,918 Cogen Cost ($/kW) 1,650 700 1,300 815 700 1,300 747 1,000 Fuel Storage and Handling ($/MBH) 250,000 250,000 250,000 250,000 250,000 250,000 250,000 250,000 Boiler Efficiency 0.75 0.64 0.75 0.75 0.61 0.77 0.9 0.57 Cogen Efficiency 0.3 0.5 0.37 0.47 0.33 0.45 0.35 0.35 Boiler Capacity Factor 0.85 0.85 0.85 0.85 0.85 0.85 0.85 0.92 Hx Effectiveness 0.7 0.8 0.8 0 0.8 0.8 0 0.6 Fixed Cost Per Ton 20 20 20 20 20 20 20 20 Trucking Cost ($/mi/ton) 1 1 1 1 1 1 1 1 Federal Production Tax Credit ($/kWh) 0.01 0.019 0.019 0.019 0.019 0.019 0.019 0.019 Biomass O&M Cost ($/yrMBH) 15,000 25,079 57,518 43,139 25,079 31,452 24,913 43,377 

92 ANSI/ASHRAE Standard 62.1-2007. “Ventilation for Acceptable Indoor Air Quality American Society of Heating, Refrigerating, and Air-Conditio

GA: ASHRAE. http://www.ashrae.org/pressroom/detail/16298. Accessed May 2010. 
95

Appendix G. Tidal Energy 

Tidal Resource Assessment

The tides are caused by the gravitational pulls on Earth by both the moon and the sun, 

with the moon’s gravitational effect, due to its close proximity to Earth, being the 

primary driver of Earth’s tides and the sun’s gravitational pull being a secondary driver. 

The lunar orbital period is 24 hours and 50 minutes, while Earth’s rotational period, 24 

hours, dictates the timing of the sun’s tidal effects. The availability of peak tidal power 

occurs twice each day but is 50 minutes later each day. This effect can best be explained 

through several diagrams. The vectors on Earth’s surface, shown in Figure G-1, represent 

the difference in the gravitational force the moon exerts at a given point on the surface 

versus the force it would exert at the center of the Earth. The resultant force vectors 

visually represent what happens to the water—in the Earth-moon plane (left-to-right as 

shown), the water is attracted to the moon causing the waters to “bulge” (i.e., high tide) 

towards the moon. Concurrently, a similar effect is seen on the opposite side. The net 

impact on the top and bottom of the sphere is the waters move away resulting in low tide.

Figure G-1. Tide-generating forces based on Earth-moon interactions93

The axis that Earth rotates on, relative to Earth’s orbital plane as it revolves around the 

sun, is tilted approximately 23°. This tilt angle is known as the declination angle. There is 

a comparable declination angle when describing Earth’s axis of rotation relative to the 

moon’s orbital plane. This positional relationship, as shown in Figure G-2, results in the 

wide range of tidal effects experienced around the globe. Areas near the equator 

experience semi-diurnal tides (i.e., two high and two low tides per day designated by the 

red and blue labels H1 and H2), while high latitudes experience diurnal tides (shown as 

the green L and H). Mid-latitude regions experience mixed diurnal tides—two tides per 

day—but with significant diurnal inequality between successive high and low tides.

 93 Simanek, D., Emeritus Prof. of Physics, Lock Haven University of Pennsylvania. Email 12/4/2011.

To distant 

attracting mass M
96

Figure G-2. Influence of the moon’s declination on tidal forces94

The periodic nature and variances of the semi-diurnal, mixed, and diurnal tides can be 

seen in Figure G-3. The period of the lunar tides is roughly 12 hours and 25 minutes, and 

they are semi-diurnal—occurring twice each day (or, more precisely, twice every 24 

hours and 50 minutes). The influence of the moon on the tides changes as the moon’s 

declination progresses from its extreme position over the north tropics to over the south 

tropics in 14 days, with the strongest tidal pulls from the moon at these extremes. In 

between, when the moon is over the equator, the diurnal inequality of the tides is 

minimized, as occurs twice per tropical month (every 27.3 days).

Figure G-3. Graphical depiction of tidal patterns95

The moon’s gravitational pull causes the tidal bulge (i.e., water levels rise). The sun’s

gravitational pull also causes a tidal bulge, but its amplitude is only 46% as high as the 

lunar bulge.96

 94 Hagerman, G.; Polagye, B. “Methodology for Estimating Tidal Current Energy Resources and Power Production by 

Tidal In-Stream Energy Conversion (TISEC) Devices,” EPRI, 2006. 

In the absence of the moon, the solar tides would be very periodic or 

diurnal—every 12 hours. Additionally, the solar tidal bulge would always be towards the 

95 Hagerman, G.; Polagye, B. “Methodology for Estimating Tidal Current Energy Resources and Power Production by 

Tidal In-Stream Energy Conversion (TISEC) Devices,” EPRI, 2006. 96 Hagerman, G.; Polagye, B. “Methodology for Estimating Tidal Current Energy Resources and Power Production by 

Tidal In-Stream Energy Conversion (TISEC) Devices,” EPRI, 2006. 
97

sun; in other words, it would be the same time every day with high tide at solar noon 

(with corresponding high tide on the opposite side of the earth at solar midnight).

Figure G-4 illustrates the varying influence of the moon and sun on Earth’s tides. The 

light royal blue oval represents the lunar bulge and the turquoise oval represents the solar 

bulge. When the moon and the sun are pulling in the same direction (first Earth diagram 

on the left in Figure G-4), it causes the highest high tide, known as the spring tide. In the 

next phase (i.e., shown as third quarter), the moon and sun are pulling in different 

directions 90° apart. This results in lower high tides and higher low tides. This 

phenomenon is known as the neap tide, and it occurs during both the first and third 

quarters of the moon. During the half moon, new moon, and full moon, the lunar and 

solar tidal bulge work in unison, resulting in a spring tide, due to the effect described in 

Figure G-1.

There are other factors that affect the tides, such as wind, storms, salinity, or even spring 

run-off, but often the factors have smaller magnitudes and longer periods (except for 

storm impacts). For all practical purposes, a 29-day site-specific resource analysis yields 

enough information to generate a reliable tidal flow assessment enabling a usable annual 

tidal flow prediction. 

Figure G-4. Position of the moon and resultant lunar and solar spring and neap tides97

Tidal Parameters for Power Production

The tidal current speed is a critical parameter in resource assessment; however, since it 

does vary significantly through the various periodic influences of the moon and sun, it is 

also critical to determine how many periods the tidal current is at each distinct velocity 

using the frequency distribution approach used in wind resource assessment.

 97 Night Skies, Moon, Absolute Axarquia. http://www.absoluteaxarquia.com/nightsky/moon.html. Accessed Sept 

2010.
98

Figure G-5. Sample tidal current speed distribution98

The turbines operate in three regions: below cut-in speed, cut-in speed to rated speed, and 

greater than rated speed in the same manner as wind turbines. This can be seen 

graphically in Figure G-6.

Figure G-6. Sample turbine output power versus flow speed99

Newport Tidal Height and Period Assessment

There is an existing station, Newport - Station ID: 8452660,

100

The following series of four graphs (Figure G-7, Figure G-8, Figure G-9, and Figure G10) illustrates the variability in the periodic tide levels at the Newport station. The mean 

for measuring the tides at 

NAVSTA Newport that reports regularly to the National Oceanic and Atmospheric 

Administration (NOAA) Tides & Currents database. 

 98 Hagerman, G.; Polagye, B. “Methodology for Estimating Tidal Current Energy Resources and Power Production by 

Tidal In-Stream Energy Conversion (TISEC) Devices,” EPRI, 2006. 99 Hagerman, G.; Polagye, B. “Methodology for Estimating Tidal Current Energy Resources and Power Production by 

Tidal In-Stream Energy Conversion (TISEC) Devices,” EPRI, 2006. 100 National Oceanographic and Atmospheric Administration. “Tides & Currents.” 

http://tidesandcurrents.noaa.gov/station_info.shtml?stn=8452660%20Newport,%20RI. Accessed October 8, 2011.
99

range (MN) of the tides is the difference in height between the mean high water mark and 

the mean low water mark. For Newport, the MN is 3.47 ft. The diurnal range (GT) is the 

difference in height between the mean higher high water and the mean lower low water 

mark. For Newport, the GT is 3.85 ft. 

The periodic nature of tidal flow means the tidal current will reverse flow direction four 

times per day for ebb (towards low tide) and flood (towards high tide) cycles. For most of 

the day, the tides are either moving in or out. It is only during the transitional time from 

tide coming in versus going out, aka slack water, that there is very little velocity current 

in the water. The slack water duration varies site to site, but the duration is usually in the 

5–30-minute range with shorter times associated with higher tidal current velocities and 

vice versa. The approximate velocity of the tide is represented visually by the steepness 

of the sinusoidal curves in Figure G-7. The tops and bottoms of these curves are where 

the tidal current slows and then becomes neutral (i.e., zero current speed) as it transitions 

from ebb to flood or vice versa. Figure G-7 shows a fairly “normal” two-day tidal 

oscillation. The graph shows the water level relative to the mean lower low water level, 

which serves as the baseline.

Figure G-7. Newport tide level per mean lower low water—48 hr profile (MLLW)101

Figure G-8 demonstrates the accuracy of tidal predictions with the predicated water levels 

in blue, the actual water levels in red, and the difference between them shown in green.

 101 National Oceanographic and Atmospheric Administration. “Tides & Currents.” 

http://tidesandcurrents.noaa.gov/noaatidepredictions/viewDailyPredictions.jsp?Stationid=8452660. Accessed October 

20, 2011.
100

Figure G-8. Predicted versus observed tide levels in Newport102

The seven-day timeframe for Figure G-9 more clearly illustrates the impact of the solar 

tides on the lunar tides.

Figure G-9. Newport tide level per mean lower low water level—Seven-day profile103

The 30-day profile, as shown in Figure G-10, shows great consistency in period length 

but considerable variation in the water height or amplitude.

 102 National Oceanographic and Atmospheric Administration. “Tides & Currents.” 

http://tidesandcurrents.noaa.gov/gmap3/. Accessed October 8, 2011. 103 National Oceanographic and Atmospheric Administration. “Tides & Currents.” 

http://tidesandcurrents.noaa.gov/noaatidepredictions/viewDailyPredictions.jsp?Stationid=8452660. Accessed October 

8, 2011.
101

Figure G-10. Newport tide level per mean lower low water level—30-day profile104

Tidal Current Assessment 

Wind power is a very site-specific renewable resource; tidal power even more so. Site 

characteristics that are generally more favorable to better tidal current flows are narrow 

channels between land masses that large volumes of water must pass through. Due to 

lunar and solar gravitational pull, a given volume of water will need to accelerate to move 

through the channel. The full tidal stream resource is a function of both the speed of the 

tidal current (incident power density) and the channel cross-sectional area (width and 

depth).105

The impact of terrain on the viability of a particular site is very significant. To analyze 

that terrain, two studies will need to be undertaken: (1) a detailed bathymetry mapping of 

NAVSTA Newport’s accessible waterway bed (in Narragansett Bay) and (2) a tidal 

current flow study with measurements at specific sites of interest as identified by the 

bathymetric study. 

Shown in Figure G-11 and Figure G-12 are high-level bathymetry maps of Narragansett 

Bay. The complexity of terrain above the water can be similar to the complexity below 

the water surface in many areas; however, the impact of this terrain variation on viable 

current flow (i.e., power in the water flow) underwater is greatly magnified compared to 

the influence of the terrain on wind current flow (i.e., power in the wind) due to the 

greatly increased density of the fluid in the bay (water density = 62.32 lbm/ft3 or 998.2 

 104 National Oceanographic and Atmospheric Administration. “Tides & Currents.” 

http://tidesandcurrents.noaa.gov/noaatidepredictions/viewDailyPredictions.jsp?Stationid=8452660. Accessed October 

8, 2011.

105 Hagerman, G.; Polagye, B. “Methodology for Estimating Tidal Current Energy Resources and Power Production by 

Tidal In-Stream Energy Conversion (TISEC) Devices,” EPRI, 2006.
102

kg/m3

) versus the air above the bay (air density = 0.076 lbm/ft3 or 1.2 kg/m3). 

Topographical maps are used to illustrate the terrain gradients above the water;

bathymetrical maps are used to illustrate terrain gradients below the surface. 

For the bathymetry map in Figure G-11, the lighter blue shading indicates shallow water, 

the darker blue indicates deeper channels. The Navy chose Newport as a Naval base site 

because the waterway was deep enough for large Navy vessels. For tidal current, 

generally shallow and narrow channels are preferred as these features tend to accelerate 

the flow of the volume of water that is moving due to the lunar and solar tidal pull.

Figure G-11. Bathymetry map of Rhode Island

Credit: Paul Jordan, Rhode Island Department of Environmental Management

The contour map (Figure G-12) gives better definition to the channels and depths, though 

it is still lacking in enough site-specific resolution to determine best locations for 

increased tidal current flows. Micro-siting is used to determine the best location for wind 

turbines on land. Extreme micro-siting with much higher resolution are needed for 

investigation of the potential tidal current resource.
103

Figure G-12. 10 ft (3.1 m) contour map of Narragansett Bay

Credit: Paul Jordan, Rhode Island Department of Environmental Management

To determine the extent of the tidal resource available to NAVSTA Newport, it would be 

useful to effectively characterize the surface of the Narragansett Bay floor in areas that 

NAVSTA Newport could install a turbine if the resource proves viable. Key features of 

interest are canyons or channels—features that would cause the acceleration of the tidal 

current.

Tidal Current Data

Table G-1 shows the type of data NAVSTA Newport will need to collect to be able to 

determine if the tidal resource is economic. The table shows the tidal current speeds (in 

knots and m/s) and direction (flood = +, ebb = -). Looking across the pink highlights for 

Day 1, the maximum current is at 6:21 a.m. at 0.3 knots (0.15 m/s). At 11:17 a.m., the 

maximum current is -0.5 knots (-0.26 m/s). The vertical green shaded boxes show how 

the time of the maximum velocity is a little bit later in successive days by approximately 

20–55 minutes. 
104

Table G-1. Predicted Tidal Currents at Quonset Point in Narragansett Bay106

Once the best potential locations for tidal current concentration or acceleration are 

determined via the detailed bathymetrical analysis, installing an underwater data 

acquisition system (DAS) with open channel flow meter is recommended. For 

expediency, installing several flowmeters at a time is recommended. Due to the periodic 

nature of the tidal flows as explained over the previous several pages, the measurement 

campaign per site only needs to be 29 days long; then the various influences on the tidal 

flow repeat. The assessment of 5–20 locations should take 3–18 months, depending on 

how many DAS are deployed.

Tidal Power Calculations

Due to the much higher density of water than air, the tidal current velocities for effective 

power conversions are considerably lower than the air or wind velocities required for 

wind turbines. There are variations in the tidal stream speeds per the above discussion on 

 106 National Oceanographic and Atmospheric Administration. “Tides & Currents.” 

http://tidesandcurrents.noaa.gov/currents06/QUONSET.shtml. Accessed October 8, 2011.

 Quonset Point, Narragansett Bay, Rhode Island NOAA, National Ocean Service

Predicted Tidal Current January, 2006 Flood Direction, 21 True. Ebb (-)Direction, 200 True.

Slack Max Max Max Slack Max Max Max Slack Max Max Max Slack Max Max Max Slack

Water Current Current Current Water Current Current Current Water Current Current Current Water Current Current Current Water

Day Time Time Veloc Veloc Time Time Veloc Veloc Time Time Veloc Veloc Time Time Veloc Veloc Time

h.m. h.m. knots m/s h.m. h.m. knots m/s h.m. h.m. knots m/s h.m. h.m. knots m/s h.m.

1 151 621 0.3 0.15 834 1,117 -0.5 -0.26 1,452 1,852 0.3 0.15 2,056 2,333 -0.5 -0.26

2 242 713 0.3 0.15 925 1,205 -0.5 -0.26 1,538 1,947 0.3 0.15 2,149 0.00

3 23 -0.5 -0.26 333 811 0.3 0.15 1,017 1,255 -0.5 -0.26 1,621 2,044 0.3 0.15 2,242

4 117 -0.5 -0.26 425 909 0.3 0.15 1,110 1,347 -0.5 -0.26 1,703 2,139 0.3 0.15 2,337

5 211 -0.5 -0.26 521 1,006 0.3 0.15 1,206 1,438 -0.5 -0.26 1,750 2,233 0.3 0.15

6 32 303 -0.5 -0.26 637 1,103 0.3 0.15 1,301 1,527 -0.4 -0.21 1,847 2,328 0.3 0.15

7 128 357 -0.4 -0.21 909 1,159 0.3 0.15 1,357 1,621 -0.4 -0.21 1,954 0.00

8 23 0.3 0.15 225 502 -0.4 -0.21 1,019 1,253 0.3 0.15 1,454 1,727 -0.4 -0.21 2,058

9 115 0.3 0.15 325 623 -0.4 -0.21 1,115 1,347 0.3 0.15 1,553 1,839 -0.4 -0.21 2,153

10 210 0.3 0.15 431 728 -0.4 -0.21 1,203 1,444 0.3 0.15 1,653 1,937 -0.4 -0.21 2,241

11 313 0.3 0.15 533 820 -0.4 -0.21 1,243 1,545 0.3 0.15 1,748 2,028 -0.4 -0.21 2,326

12 413 0.3 0.15 625 909 -0.5 -0.26 1,315 1,638 0.3 0.15 1,837 2,117 -0.5 -0.26

13 9 501 0.3 0.15 710 955 -0.5 -0.26 1,339 1,721 0.3 0.15 1,922 2,204 -0.5 -0.26

14 54 539 0.3 0.15 752 1,040 -0.5 -0.26 1,408 1,800 0.3 0.15 2,006 2,250 -0.5 -0.26

15 140 614 0.3 0.15 831 1,123 -0.5 -0.26 1,442 1,838 0.3 0.15 2,050 2,335 -0.5 -0.26

16 228 648 0.3 0.15 909 1,205 -0.5 -0.26 1,518 1,917 0.3 0.15 2,132 0.00

17 20 -0.5 -0.26 726 0.2 0.10 1,248 -0.4 -0.21 2,000 0.2 0.10

18 106 -0.4 -0.21 812 0.2 0.10 1,329 -0.4 -0.21 2,043 0.2 0.10

19 151 -0.4 -0.21 901 0.2 0.10 1,407 -0.4 -0.21 2,127 0.2 0.10

20 230 -0.4 -0.21 949 0.1 0.05 1,439 -0.3 -0.15 2,210 0.2 0.10

21 303 -0.3 -0.15 1,039 0.1 0.05 1,509 -0.3 -0.15 2,257 0.2 0.10

22 336 -0.3 -0.15 1,129 0.1 0.05 1,545 -0.3 -0.15 2,346 0.2 0.10

23 417 -0.3 -0.15 1,218 0.1 0.05 1,632 -0.2 -0.10 0.00

24 35 0.2 0.10 527 -0.2 -0.10 1,307 0.1 0.05 1,749 -0.3 -0.15

25 125 0.2 0.10 704 -0.3 -0.15 1,358 0.2 0.10 1,908 -0.3 -0.15

26 221 0.2 0.10 756 -0.3 -0.15 1,459 0.2 0.10 2,001 -0.4 -0.21 2,313

27 327 0.3 0.15 545 841 -0.4 -0.21 1,603 0.2 0.10 2,050 -0.4 -0.21

28 0 427 0.3 0.15 638 927 -0.5 -0.26 1,302 1,657 0.3 0.15 1,857 2,139 -0.5 -0.26

29 48 517 0.4 0.21 728 1,013 -0.5 -0.26 1,347 1,745 0.3 0.15 1,949 2,228 -0.5 -0.26

30 138 605 0.4 0.21 817 1,059 -0.5 -0.26 1,432 1,833 0.4 0.21 2,040 2,317 -0.5 -0.26

31 231 655 0.4 0.21 907 1,145 -0.6 -0.31 1,514 1,925 0.3 0.15 2,131 0.00
105

lunar, solar, and other factors. An effective range for the average of the spring and neap 

tidal current speeds is in the range of 2–3 m/s or 4–6 knots.107

The power equation for water is essentially the same as for wind, only the fluid has 

changed (from air to water).

 

The power available in the tidal current is given by:

P = 1⁄2 * A * ρ * V3

where

P = power of the tidal current [W]

A = swept area of the rotor (blades) [m2] = πD2/4 = πr

2

ρ = density of the water [kg/m3] (1,000 kg/m3 at sea level at 5°C)

V = velocity of the water [m/s]

The velocity of the water, being cubed for power calculations, has a significant impact on 

the viability of any site. Rearranging the equation, the power density can be determined 

by 

(P/A) = 1⁄2 * ρ ∗ V3 (watts / m2

)

 107 Hagerman, G.; Polagye, B. “Methodology for Estimating Tidal Current Energy Resources and Power Production by 

Tidal In-Stream Energy Conversion (TISEC) Devices,” EPRI, 2006.
106

Table G-2 shows the impact of tidal current speed on power density as a result of the 

cubic relationship that exists between the two.

Table G-2. Power Density at Different Tidal Current Speeds108

 108 Hagerman, G.; Polagye, B. “Methodology for Estimating Tidal Current Energy Resources and Power Production by 

Tidal In-Stream Energy Conversion (TISEC) Devices,” EPRI, 2006.
107

Appendix H. Geothermal Energy

Systems Configuration and Characteristics

Geothermal systems are not a “one-size-fits-all” technology. There are a number of 

variables and factors that must be considered for each system that encompass factors,

such as available land area (determines vertical versus horizontal system), soil type 

(conductivity, moisture content, and diffusivity), seasonal weather variation (temperature 

and humidity), building loads (energy use and building envelope), type of system 

(groundwater, ground-coupled, and lake loop), and type of loop (vertical, horizontal, or 

spiral). For example, heat pump efficiencies for all energy systems vary significantly 

according to type of equipment and operating conditions. The energy requirements of the 

location vary according to the outside air conditions (temperature, wind, and humidity) 

and the envelope of the structure (insulation, infiltration, and fenestration).

The typical closed loop GSHP system consists of three types of loops: a ground or 

subsurface loop, a refrigerant loop, and the cooling/heating distribution loop. The 

subsurface loop typically consists of polyethylene or polybutylene pipe, which is placed 

in the ground either horizontally in a trench or vertically in a boring or well. This thinwalled pipe acts as a heat exchanger, which transfers heat from or to the ground (may 

also be designed to exchange with a body of water). Antifreeze fluids inside the pipe are 

circulated to the heat exchanger of an indoor heat pump where it releases heat to the 

refrigerant. The refrigerant loop typically consists of copper pipes that contain a 

refrigerant. The cooling/heating distribution loop of the system consists of the forced air 

or hydronic system to distribute the heated or cooled air throughout the building.109

A GSHP connects to the earth as its heat sink for thermal exchange. This connection can 

be earth, groundwater, or surface water coupled. Details of several types of the ground 

exchange systems typically used today can be found in Appendix C.

A 

fluid (usually water or a mixture of water and antifreeze) circulates through the pipes to 

absorb or relinquish heat within the ground.

Heat Pumps

The heat pump itself is a critical piece of equipment in GSHP systems. The use of heat 

pumps in GSHP systems is what allows the system to effectively take advantage of the 

heating or cooling provided by the earth.

Heat pumps operate in a very efficient manner as they are not generating heat per se, they 

are merely moving it. It takes a lot less energy to move heat than to generate it. A 

comparison of how much energy a system delivers compared to how much it consumes 

helps to illustrate why the energy savings can be so great in these systems compared to 

conventional HVAC systems. The efficiency of heating equipment is often measured by 

its coefficient of performance (COP). The COP is a ratio of how much energy a system 

delivers relative to what it consumes in the process. It is defined, more specifically, as the 

heating capacity (in Btu/hr) of the heating unit divided by its electrical input (also in 

 109Bureau of Water Quality Management. "3. Closed-Loop GSHP Systems," Appendix L, Ground Source Heat Pump 

Manual, Commonwealth of Pennsylvania, Department of Environmental Protection, Lancaster County Planning 

Commission. http://www.co.lancaster.pa.us/planning/cwp/view.asp?a=3&Q=268215. Accessed October 8, 2011. 
108

Btu/hr) at standard (ARI/ISO 13256-1) conditions of 32°F (0°C) entering water for 

closed loop models and 50°F (10°C) entering water.110

Some average COP values for heating equipment are111

• Advanced water to air heat pump 4.0

:

• Water to air heat pump 3.0

• Air to air heat pump 2.0

• Electric resistance 1.0

• Natural gas furnace 0.7

• Coal furnace 0.7.

Figure H-1 illustrates the major components of a heat pump. The water-to-refrigerant coil 

exchanges heat with the ground loop.

Figure H-1. Typical geothermal heat pump configuration112

Figure H-2 illustrates how the entering water temperature (from the earth) impacts the 

GHP performance relative to its capacity, which in turn affects its ability to meet the 

load. The steady temperatures provided by the earth enable the heat pumps to operate 

near peak capacity in both heating and cooling modes. An air-source heat pump, which 

relies on ambient air for a large part of its thermal energy, can operate at low heating 

capacities when the outside air is below 50°F (10°C) and at low cooling capacities when 

outside air is above 80°F (27°C).

 110 DOE FEMP. “How to Buy an Energy-Efficient Ground-Source Heat Pump.”

http://www.ornl.gov/sci/femp/pdfs/gshp-pro-chal.pdf. Accessed October 8, 2011. 111 Lancaster County Planning Commission. Appendix L: IGSHPA Closed-Loop/Geothermal Heat Pump Systems -

Design and Installation Standards, Commonwealth of Pennsylvania, Department of Environmental Protection. 

http://www.millersvilleborough.org/planning/cwp/view.asp?A=2&Q=268208. Accessed October 8, 2011. 112 Shonder, J. “Geothermal Heat Pumps.” Presented at FEMP Renewable Energy Workshop, NREL 2004.
109 

Figure H-2. Capacity of a typical 4-ton GHP versus EWT113

In Figure H-3, the impact of entering water temperature on the heating COP and cooling 

energy efficiency ratio (EER) can be readily seen. Again, the steady earth temperatures 

enable a GHP to operate near both peak heating COP and peak cooling EER, which 

results in more British thermal units of heating or tons of cooling delivered per kilowatthour consumed. 

Figure H-3. Efficiency of a typical 4-ton GHP as a function of EWT114

There are a number of variables and factors that must be considered for each system on 

an individual basis. Working with qualified, experienced professionals on all aspects of 

geothermal systems is highly recommended. 

Once the site conditions are fully analyzed and the GSHP system is designed to meet the 

load, the energy performance of a GSHP system can be influenced by three primary 

factors: the heat pump machine, the circulating or well pump, and the ground-coupling or 

groundwater characteristics. An optimized GSHP system considers the interaction of 

these factors. Case studies of school and commercial building GSHP energy and 

economic performance results were less conclusive than those for the residential sector. 

 

113 Shonder, J. “Geothermal Heat Pumps.” Presented at FEMP Renewable Energy Workshop, NREL 2004. 114 Shonder, J. “Geothermal Heat Pumps.” Presented at FEMP Renewable Energy Workshop, NREL 2004. 
110

Given all the potential influences upon school and commercial building energy use, 

predictions of savings to be achieved with a GSHP system become a very site-specific 

endeavor.

115

High efficiency circulation pumps are recommended throughout the system. They are the 

consumers of electricity and if inefficient, will consume more electricity than necessary 

throughout the life of the system.

GSHP Economic Parameters

The economic justification for GSHP systems is, as is the case for many RE systems, tied 

directly to what it is being compared to. In new construction, the design alternatives are 

compared based on energy system modeling using current energy and construction cost 

data. For retrofits, a similar approach taken though the existing system typically has 

much firmer cost numbers associated with it than purely modeled systems.

In both cases, the economic comparison has two components:

• Capital costs for the design, construction, and installation of the system

• Operational costs that include cost of fuel, routine O&M, and major repairs.

In replacement of existing HVAC systems, typically, there are GSHP savings from 

reduced energy bills for heating due to the elimination of natural gas consumption. There 

are cooling energy savings due to the reduction of cooling compressor energy. There are 

also reduced O&M bills due to the simplicity of the system relative to conventional 

HVAC systems. It should be noted that if the GSHP system is replacing an electrical 

heating system, for the vast majority of the year it will be using significantly less 

electrical energy to heat the building. During a few very cold periods, the heat pumps 

have difficulty extracting enough heat from the cold and they either operate continuously 

but at low efficiency or supplement heating will be needed. The result may be an increase 

in the demand for electricity for supplemental heating.

In new construction applications, it is assumed that there will be competing HVAC 

systems for a GSHP system to be evaluated against. The capital cost of equipment, the 

price of fuel, and the annual O&M costs are the primary considerations. GSHP systems 

are generally considered to have higher upfront capital costs and lower O&M costs, 

though the mix of natural gas versus electricity will likely change. A GSHP system may 

have increased electricity consumption compared to a conventional HVAC system 

because the heat pumps are electrically driven. However, it would be expected that the 

heating fuel (natural gas, fuel oil, or electricity) consumption would decrease 

significantly through the use of a geothermal system.

Capital Costs

Generally, the vertical GSHP systems are more expensive to drill, grout, and backfill than 

horizontal or surface/ground water systems. The horizontal GSHP systems require the 

 115 Lienau, P.; Boyd, T.; Rogers, R. “Ground-Source Heat Pump Case Studies and Utility Programs.” Klamath Falls, 

OR: Geo-Heat Center, Oregon Institute of Technology; p. 40, April 1995. http://geoheat.oit.edu/pdf/hp1.pdf. Accessed 

October 8, 2011.
111

most piping and land area. Typical installed cost ranges for horizontal systems are $850–

$3,200/kW. For vertical systems, the cost range is $1,050–$5,900/kW.116

Others cite a range of costs based on building size with the caveat that a number of 

critical system design factors cannot be known before investigation, so there is 

uncertainty in the estimates. For commercially sized new construction, the estimated cost 

is in the $13–$17/ft2 range.

Water well 

systems, either open loop or standing column well, are in the $850–$1,500/kW range.

117 For commercial retrofit applications where re-using 

portions of the existing ducting and delivery system is likely, the range is $10–$13/ft2 

(wide variation due to small dataset).118 For water well systems, the installed cost per ton 

is in the $3,000–$5,000/ton range (open loop and standing column well).119

Operating Costs and Savings Based on Fuel Prices

As shown in Figure H-4, the annual dollar savings for a GSHP application are greater 

when the cost of natural gas is high and the cost of electricity is low. The estimated 

savings when replacing natural gas in the United States is in the $8–$900/year range. The 

cost of natural gas and electricity in the United States is relatively low compared to most 

of the other countries in the study. The current U.S. natural gas price of approximately 

$3.00/GJ is roughly equivalent to $3.37/MMBtu or dekatherm.120 With these extremely 

low natural gas prices, the economics of GSHP systems become more challenging.

Figure H-4. Annual GSHP savings versus cost of natural gas121

 116 RETScreen. Online Manual. Version 4. www.retscreen.net/download.php/Ang/470/0/SWH3.pdf. Accessed 

October 8, 2011. 

117 Shonder, J. “Geothermal Heat Pumps.” Presented at FEMP’s Implementing Renewable Energy Projects Workshop. 

August 2006. 

118 Ibid. 119 Ibid. 120 U.S. EIA. “Natural Gas Weekly.” http://www.eia.doe.gov/oog/info/ngw/ngupdate.asp. Accessed October 8, 2011. 121 Hanova, J.; Dowlatabadi, H. Strategic GHG Reduction Through the Use of Ground Source Heat Pump Technology. 

Vancouver, Canada: University of British Columbia, 2007. http://iopscience.iop.org/1748-9326/2/4/044001/fulltext. 

Accessed October 8, 2011.
112

Figure H-5 is similar to Figure H-4, except that the comparison is for the GSHP replacing 

fuel oil used in a furnace or boiler. The annual savings have increased by approximately 

$200 to about $1,000 annually. Note that fuel oil is not readily available or used for 

heating in a number of the countries that were used in the natural gas comparison of the 

previous graph, hence there are only a small number of countries in the comparison.

Figure H-5. Annual GSHP savings versus cost of natural gas122

In Figure H-6, the comparison is to replacing heating by electricity with resistive heaters 

to GSHP. The annual savings, at approximately $1,500/year, are nearly twice that of 

replacing natural gas heaters with GSHP systems.

 122 Hanova, J.; Dowlatabadi, H. Strategic GHG Reduction Through the Use of Ground Source Heat Pump Technology. 

Vancouver, Canada: University of British Columbia, 2007. http://iopscience.iop.org/1748-9326/2/4/044001/fulltext. 

Accessed November 8, 2011.
113

Figure H-6. Annual GSHP savings versus cost of electricity for heating123

Operation and Maintenance Costs

As with any mechanical system, the O&M costs for GSHP systems can vary widely 

depending upon a variety of factors. One key factor is the variation in system types and 

configurations. Vertical, horizontal, groundwater source, and ground-coupled systems all 

operate under different parameters so it is difficult to make a comparison of operating 

costs across all systems. Based on recent studies by Kentucky Utilities and Nebraska’s 

Lincoln Electric System,

124 the O&M costs of GeoExchange systems were estimated to 

be 12%–19% lower than traditional systems over a 20-year period. AHSRAE manuals 

estimate up to 50% O&M savings with maintenance costs averaging $0.12–$0.15/ft2

versus $0.30/ft2 for conventional systems.125

GSHP Annual Emissions Impacts

The annual emissions reduction associated with GSHPs is dependent upon the fuel source 

of the HVAC system it is displacing. For example, there are more GHGs and other 

emissions typically associated with coal-fired electricity than with direct burning of 

natural gas in a boiler. There are few GHGs associated with wind, solar, or nuclear 

power. The fossil fuel consumption reductions attributed to the GSHP will depend on the 

specifics of the application. If electricity consumption increases for heating with heat 

pumps versus heating with natural gas, emission impact calculations must include both 

the added emissions for increased electricity consumption and the offset for natural gas 

consumption reduction.

 123 Hanova, J.; Dowlatabadi, H. Strategic GHG Reduction Through the Use of Ground Source Heat Pump Technology. 

Vancouver, Canada: University of British Columbia, 2007. http://iopscience.iop.org/1748-9326/2/4/044001/fulltext. 

Accessed November 8, 2011.

124GEOEXCHANGE. “The Best Business Decision for Heating and Cooling Commercial Buildings.” 

http://www.sesnet.com/GeoExchange.pdf . Accessed June 2011. 125 GEOEXCHANGE. http://www.geoexchange.org/pdf/School2.pdf. Accessed October 8, 2011.
114

If the GSHP is replacing an all-electric HVAC system and will use significantly less 

electrical energy overall, the emissions benefits are straightforward and substantial 

compared to scenarios where the GSHP is replacing natural gas heating.

Due to the variables outlined above and their individual impacts on system design 

approaches and costs, even though they are dependent upon site-specific geotechnical 

information, which can both vary widely and drive the design decisions in very different 

directions, no cost modeling was undertaken. It is recommended that when an appropriate 

candidate building has been identified for a potential GSHP system, NAVSTA Newport 

(or NREL) initiates a geotechnical investigation to establish the parameters from which a 

reasonable economic analysis can be undertaken. 

Newport Soil Characteristics

Geotechnical investigations—a soil analysis—is one of the first activities that should be 

completed when considering a GSHP as the results of the analysis will drive both the 

types of systems to consider and the sizing of ground-coupled, heat exchange loop. 

Generally speaking, soil that has high conductivity, density, and heat capacity will 

provide greater heat exchanging capability and will positively impact overall system 

performance and economics. Wet or damp soil is generally a better heat transfer medium 

than dry soil. Fine-grained soil is generally a better heat transfer medium than coarsegrained soil. 

High conductivity is needed to effectively exchange heat from the fluid in the system 

pipes to the ground on a seasonal basis. With high conductivity, the heat exchange will 

occur more rapidly and the system performance will be more effective. Thermal 

capacitance of the soil is another characteristic that will enhance GSHP system 

performance. Soil reports for Newport were found online and are in Appendix B. Overall, 

the soil descriptions and moisture content appear to be within the parameters often used 

with GSHP. Of course, these conditions are site specific and a geotechnical investigation 

should be conducted for each building that NAVSTA Newport proposes a GSHP system. 
115

Figure H-7 indicates that Rhode Island soils have a low potential to result in scaling to 

GSHP systems. This is a positive finding for GSHPs in general as high-scaling potential 

can reduce system performance and increase O&M.

Figure H-7. Scaling potential of groundwater aquifer126

The bedrock in the Newport area will typically be granite.127 The depth to bedrock is 

usually greater than 6 ft.128

As the Wisconsin Ice Sheet receded about 10,000 years ago, it traveled southward and 

scraped away the existing soil and rock down to the bedrock. The soil and rock were 

carried in the ice until it melted, at which time the soil was re-deposited as a well-graded 

mixture of gravel, sand, silt, and clay called glacial till. Glacial till is typically 

encountered immediately overlying bedrock and can be composed of transported material 

as well as local bedrock. The composition of the till in Rhode Island varies depending on 

the bedrock that the till is derived from. The Narragansett till plains around Narragansett 

In the Providence area there are locations where it is known 

to be several hundred feet down. This investigation did not reveal a comparable level of 

known bedrock depth in Newport, but descriptions of glacial movements and general 

terrain imply it is considerably shallower. Depth to bedrock will determine if a vertical or 

horizontal piping orientation is the most economic. Solid rock can be effective as the heat 

exchange medium in vertically-oriented systems but is typically more expensive to drill.

 126 Rafferty, K. “Scaling in Geothermal Heat Pump Systems.” Geo-Heat Center, Oregon Institute of Technology, 

Klamath Falls, OR. http://www.docstoc.com/docs/68850745/Scaling-in-Geothermal-Heat-Pump-Systems. Accessed 

October 27, 2011.

127 “Baxter, C.D.P., Page, M., and Bradshaw, A.S., and Sherrill, M. (2005). Guidelines for Geotechnical Site 

Investigations in Rhode Island. FHWA-RIDOT-RTD-05-1S, p. 104. 128 NEsoil.com. New England Soil Profiles, Newport Series. http://nesoil.com/muds/newport.htm. Accessed October 8, 

2011.
116

Bay are derived from sedimentary rock, shale, sandstone, conglomerate, and, in some 

locations, coal.129

Closed Loop Systems

A horizontal closed loop system, shown in Figure H-8, is based on the stacking of two 

pipes in a horizontally-oriented heat exchange field. These systems may be connected in 

series or in parallel. The horizontal heat exchange fields may be a single pipe as shown or 

there may be multiple pipes (two, four, or six) or a spiral-wound coil, aka “slinky” 

(Figure H-9). The multiple pipe or coil systems are designed to increase the heat 

exchange surface area. The system as shown is in heating mode as low temperature heat 

exchange fluid in the subsurface loop is rejected from the building, exchanged with the 

earth and warmer temperature heat exchange fluid is returned to the building.

Figure H-8. Horizontal bore, closed loop GSHP system130

These horizontally-oriented systems often have the lowest initial costs but require the 

largest area. These systems may be located in an adjacent field (e.g., athletic field, 

playground/park, or vacant), next to a building, or under a parking lot. The construction 

process for these systems can be disruptive at existing building sites. The location of 

underground utilities must be considered in the initial design phase. Once installed,

however, the piping is expected to have an in-ground life of 30–40 years (the 

International Ground Source Heat Pump Association states 50 years131

Horizontal systems generally require 250–300 ft2 (23–28 m2) of land per ton of heating or 

cooling. Horizontal systems that employ wound coils typically extend 4–8 ft (1.2–2.4 m) 

in diameter and 2–8 ft (0.6–2.4 m) down. There is a much higher total heat exchange 

surface area per square foot (or square meter) of bore field, but there is some loss of 

efficiency due to the short distance between the coiled tubes. However, when limited 

space is an issue or if there is a desire to lower the installation cost, this sort of borehole 

field compression can prove to be worthwhile.

), so near-term 

land disturbances should not be an issue. Of course, future use of the land must be 

considered as there will be limitations on activities that may be undertaken at the site.

 129 Baxter, C.; Page, M.; Bradshaw, A.; Sherrill, M. “Guidelines for Geotechnical Site Investigations in Rhode Island –

Final Report.” Rhode Island Department of Transportation, March 2005. 

http://www.dot.ri.gov/documents/engineering/research/Reports/Site_inv_guidelines.pdf. Accessed October 8, 2011. 130 Sanner, B. “Shallow Geothermal Energy.” http://geoheat.oit.edu/bulletin/bull22-2/art4.pdf. Accessed October 8, 

2011.

131 International Ground Source Heat Pump Association. “Ground Source Heat Pumps Offer Great Benefits.” 

http://www.igshpa.okstate.edu/geothermal/commercial.htm. Accessed October 8, 2011. 
117

Figure H-9. Horizontal bore, closed loop GSHP with spiral coil132

The energy performance of a GSHP system can be influenced by three primary factors:

the heat pump machine, the circulating or well pump, and the ground-coupling or 

groundwater characteristics.133

Horizontal systems are best suited to applications that have both heating and cooling 

loads, even simultaneously, as they can best take advantage of solar-radiation-driven 

surface temperature fluctuations on an annual basis. Since these systems depend on the 

solar radiation for a significant portion of thermal recharging, attention should be paid to 

the types of covering of the surface above the horizontal system in the ground. Any 

coverings that significantly alter the solar radiation impacts on the surface should be 

avoided.

An optimized GSHP system considers the interaction of 

these factors.

134

 132 DOE. “Types of Geothermal Heat Pump Systems.” 

http://www.energysavers.gov/your_home/space_heating_cooling/index.cfm/mytopic=12650. Accessed October 8, 

2011. 

133 Lienau, P.; Boyd, T.; Rogers, R. Ground-Source Heat Pump Case Studies and Utility Programs. Klamath Falls, OR: 

Geo-Heat Center, Oregon Institute of Technology; p. 13, April 1995. http://geoheat.oit.edu/pdf/hp1.pdf. Accessed 

October 8, 2011. 134 Sanner, B. “Shallow Geothermal Energy.” Giessen, Germany: Justus-Liebig University. 

http://geoheat.oit.edu/bulletin/bull22-2/art4.pdf. Accessed October 8, 2011.
118

The vertical closed loop system in Figure H-10 is based on a one U-tube per borehole 

type ground heat exchanger. When land area for the system is limited, this is often the 

system of choice even though installation costs are higher than with horizontal systems. 

The operational costs of these systems are usually lower than horizontal systems due to 

overall higher efficiencies as the heat source and sink have a near-constant year-round 

temperature. Because of the depth of these systems, the impact of solar radiation is 

minimal, so there are not typically any restrictions on surface coverings.

Plastic pipes (polyethylene or polypropylene) are installed in the boreholes and backfilled with grout to ensure effective heat transfer. There may be one, two, or three Utubes per borehole. Due to the cost of drilling boreholes for vertical systems, test 

boreholes are commonly drilled to assess the thermal conductivity of the soil. This is 

critical information for system sizing the ground-coupled loop.

Figure H-10. Vertical bore, closed loop GSHP system135

 135 DOE. “Types of Geothermal Heat Pump Systems.” 

http://www.energysavers.gov/your_home/space_heating_cooling/index.cfm/mytopic=12650. Accessed October 8, 

2011. 
119

The slinky approach, shown in Figure H-11, can be used on shallow vertical systems, 

though these are more typically used in residential-size systems with limited boreholefield area.

Figure H-11. Closed loop, water-source coil system136

A water source closed loop system can be employed in a variety of climates providing the 

water source has enough depth to provide year-round temperatures above freezing. A 

typical thermal pattern for lakes in the winter has the coldest water (or ice) near the 

surface while the water near the bottom is around 39°F (4°C), at which maximum density 

for water occurs.137

Open Loop Systems

Propylene glycol is commonly used as the heat exchange medium in 

these systems as it also an effective anti-freeze.

Given the proximity of the Narragansett Bay, open loop systems deserve a thorough 

investigation to ascertain if it is possible to use the bay as the heat sink/source for an open 

loop system. Open loop GHP systems require an open body of water such as a bay, lake,

or stream.

The water itself is the heat source or sink. In general, these systems are restricted to 

warmer climates as the heat pump and heat exchange equipment will not work effectively 

when water temperatures drop below 45°F (7°C). The exception to this is buildings in 

cooler climates with year-round cooling needs due to high internal gains.

The characteristics of the water source has a lot of system design implications, so a 

detailed temperature profile with seasonal variations should be developed or obtained 

from existing sources (state or federal geological surveys may have appropriate 

 136 DOE. “Types of Geothermal Heat Pump Systems.” 

http://www.energysavers.gov/your_home/space_heating_cooling/index.cfm/mytopic=12650. Accessed October 8, 

2011. 

137 Outside the Loop. Winter 1999–Volume 2, Number 1. http://geoheat.oit.edu/otl/otl02-01.pdf. Accessed October 8, 

2011. 
120

temperature information).138 Deeper lakes may be thermally stratified so cooler 

temperature water may be available 30–50 ft (9–15 m) below the surface on a nearly 

year-round basis. A minimum depth of 10 ft (3 m) is recommended. This depth should be 

measured at the lowest seasonal level. The maximum recommended capacity is 20 

tons/acre (8 tons/hectare) in a cooling-dominated climate and 10 tons/acre (4 

tons/hectare) in a heating-dominated climate.139

Figure H-12. Open loop lake system at left; open loop system with river or well at right140

Two aspects of using a nearby water source should be considered in detail before the 

design stage. One is the likelihood of obtaining the necessary permits to both use and to 

discharge water from a surface or underground source. Discharge of water from an open 

loop system to a surface water body, such as a stream, may require a National Pollutant 

Discharge Elimination System (NPDES) permit.141

The other aspect is in regards to the water quality itself. Hard water or water prone to 

scaling due to calcium or magnesium salts content will reduce the heat exchanger 

effectiveness over time.142

A type of open loop system used commonly in the Northeast is the standing column 

system. The systems often have very deep wells (800–1,500 ft range). In these systems, 

with favorable soil conditions, one or two wells are typically dug with no test bores done 

ahead of time.

Other water source issues, such as fouling or filtration, can be 

readily addressed using solutions developed by the power generation and process 

industries, which have used rivers and lakes extensively over the years.

143

 138 Outside the Loop. Winter 1999–Volume 2, Number 1. 

These systems operate at temperatures between typical open and closed 

loop systems. Water quality is a critical issue in these systems and water with low pH and 

hardness are desirable qualities as they reduce the potential for scaling on the pump or 

heat exchange equipment. These systems are most often used in areas with hard rock 

geology under the surface and water flow rates too low for a conventional open loop 

http://geoheat.oit.edu/otl/otl02-01.pdf. Accessed October 8, 

2011.

139 Ibid. 140 Shonder, J. “Geothermal Heat Pumps.” Presented at FEMP’s Implementing Renewable Energy Projects Workshop. 

August 2006. 

141 “Ground Source Heat Pump (GSHP) Systems.” Pennsylvania Department of Environmental Protection. 

http://www.elibrary.dep.state.pa.us/dsweb/Get/Document-80630/3920-FS-DEP2006.pdf. Accessed October 8, 2011. 142 Raferty, K. “Scaling in Geothermal Heat Pump Systems.” Geo-Heat Center Quarterly Bulletin, March 2000, pp. 

11–15. http://geoheat.oit.edu/bulletin/bull21-1/bull21-1-all.pdf. Accessed October 8, 2011. 143 Shonder, J. Telephone call. Oak Ridge National Laboratory, Oak Ridge, TN, 8 June 2011.
121

system.144 As discussed in Newport Soil Analysis section below, the Newport area has 

both hard rock geology (granite) and water with low pH and hardness. A schematic of the 

system is shown in Figure H-13.

Figure H-13. Standing column open loop GHP system145

Another version of a vertical system is an open loop system that involves the use of 

groundwater in a production well and the return of that groundwater in an injection well. 

Again, a permit may be needed for discharge into the injection well—check with local 

authorities. 

Figure H-14. Vertical open loop water well GHP system146

The more cost-effective approach with GSHP systems is to design the system to supply 

all of the heating and cooling for a building. This is most typically done in new 

construction applications. In retrofit applications, these systems can be integrated into an 

existing HVAC system’s ducting and delivering system with boilers or chillers from the 

existing system being used for auxiliary heating/cooling or as a back-up system. When 

integrated with other HVAC components, the entire system is often termed a hybrid 

GSHP system. Sometimes the hybrid approach is taken so the GSHP system can avoid 

 144 Rafferty, K. “Design Aspects of Commercial Open-Loop Heat Pump Systems.” http://geoheat.oit.edu/pdf/tp104.pdf. 

Accessed October 8, 2011.

145 Rafferty, K. “Design Aspects of Commercial Open-Loop Heat Pump Systems.” http://geoheat.oit.edu/pdf/tp104.pdf. 

Accessed October 8, 2011.

146 Sanner, B. “Shallow Geothermal Energy.” http://geoheat.oit.edu/bulletin/bull22-2/art4.pdf. Accessed October 8, 

2011.
122

the added cost of being sized for peak loads while operating significantly below peak for 

most of the year.

Newport Soil Analysis

The Newport soil analysis provided below provides useful background of the range of 

soil conditions found at the surface and below the surface for much of the state of Rhode 

Island. The information is akin to the wind maps used in the initial phases of wind 

resource assessment; they point towards areas that merit more detailed, site-specific 

investigation. 

As indicated in the Five Year Review147

If NAVSTA Newport desires to pursue GSHP technology, a site-specific geotechnical 

study will be done at several viable sites to determine the thickness of the surface 

deposits and the depth required to reach bedrock as these two factors will drive both 

appropriate system design (vertical or horizontal) and economics. Next is a profile of the 

soils in the area from the Newport Series study. It provides a great general reference, but 

detailed site-specific information is needed for next steps.

of McAllister Point, NAVSTA Newport is 

located at the southeastern end of the Narragansett Basin, which consists on non-marine 

sedimentary rock of the Pennsylvanian age. The bedrock is primarily of the Rhode Island 

Formation, and it is overlaid with glacially-derived unconsolidated deposits. According to 

the study by TtNUS (1999), cited in the Five Year Review, these surficial deposits 

consist of till, sand, gravel, and silt and range in thickness from 1 to 150 ft. NAVSTA 

Newport is located on the Narragansett till plain with stratified drift or outwash deposits 

composed of sorted sand, silt, and gravel overlying the till. 

 147 EPA. “Five Year Review Report.” http://www.epa.gov/region1/superfund/sites/netc/457973.pdf. Accessed October 

8, 2011. 
123

New England Soil Profiles, Newport Series148

Newport Soils: Very deep well-drained soils formed in compact glacial till

dominated by dark colored (Carboniferous) minerals. Newport soils are on till 

plains, smooth convex sideslopes of uplands and on drumlins. Newport soils are 

mapped primarily in the northern portion of the county.

Newport Pedon Description 2332501

Map Unit (s): 325B, 325C, 325E, 326B, 326C, 326E

Map Phases: 

325B Newport fine sandy loam, 3 to 8 percent slopes.

325C Newport fine sandy loam, 8 to 15 percent slopes.

325E Newport fine sandy loam, 15 to 35 percent slopes.

326B Newport fine sandy loam, 3 to 8 percent slopes, very stony.

326C Newport fine sandy loam, 8 to 15 percent slopes, very stony.

326E Newport fine sandy loam, 15 to 35 percent slopes, very stony. 

Taxonomic Classification: Coarse - loamy, mixed, mesic, Oxyaquic Haplorthods.

Drainage Class: Well drained.

Parent Material: Dense glacial till derived from dark colored sedimentary rocks.

Permeability: Moderate in the solum, slow or very slow in the dense substratum.

Available Water Holding Capacity: Moderate.

Soil Reaction: Very strongly acid to moderately acid throughout. .

Depth to Bedrock: Greater than 65 inches.

Seasonal High Watertable: Depth: 2.5 to 4 feet.

Type: Perched

Months: January to May.

Hydrologic Group: C.

Hydric Soil: No.

Flooding/Ponding Potential: Frequency and Type: None.

Potential Inclusions: Paxton and Montauk soils are similar inclusions. 

Moderately well drained Pittstown, Scituate, and Woodbridge soils are on 

concave and level slopes. Poorly drained Norwell, and Ridgebury soils are along 

drainageways. Also included are soil which have bedrock within 65 inches.

Soil Suitability:

Agriculture: Map unit 325B is a prime farmland soil. Map units 325C, 326C and 

326B are important farmland soils

Woodland: Well suited for woodland

 148 NEsoil.com. New England Soil Profiles, Newport Series. http://nesoil.com/muds/newport.htm. Accessed October 8, 

2011.
124

Development: Major limitations related to slow permeability in the dense till 

substratum. Large surface and subsurface stones and boulders may interfere with 

excavation. Erosion hazards are likely during development, measures should be 

taken to prevent erosion.

NEWPORT SERIES149

The Newport series consists of well drained loamy soils formed in lodgement till 

derived mainly from dark sandstone, conglomerate, argillite, and phyllite. The 

soils are very deep to bedrock and moderately deep to a densic contact. They are 

nearly level through moderately steep soils on till plains, low ridges, hills and 

drumlins. Slope ranges from 0 through 35 percent. Saturated hydraulic 

conductivity is moderately high or high in the surface layer and subsoil and low 

or moderately high in the dense substratum. Mean annual temperature is 49 

degrees F. (9 degrees C.) and mean annual precipitation is 48 inches (1219 mm). 

TAXONOMIC CLASS: Coarse-loamy, mixed, superactive, mesic Oxyaquic 

Dystrudepts 

TYPICAL PEDON: Newport silt loam - cultivated field. (Colors are for moist 

soil unless otherwise noted.) 

Ap-- 0 to 8 inches (0 to 20 centimeters); very dark brown (10YR 2/2) silt loam, 

light brownish gray (10YR 6/2) dry; weak medium granular structure; very 

friable; many fine and medium roots; 5 percent channers and gravel; strongly 

acid; clear smooth boundary. (6 to 10 inches (15 to 25 centimeters) thick.) 

Bw-- 8 to 18 inches (20 to 46 centimeters); olive brown (2.5Y 4/4) channery silt 

loam; weak medium subangular blocky structure; friable; common fine and 

medium roots; 15 percent channers and gravel; strongly acid; clear wavy 

boundary. 

Bw-- 18 to 24 inches (46 to 61 centimeters); olive (5Y 4/3) channery silt loam; 

weak medium and coarse subangular blocky structure; friable; few roots; 15 

percent channers and gravel; strongly acid; clear wavy boundary. (Combined 

thickness of the Bw horizon is 14 to 37 inches (36 to 94 centimeters).) 

Cd-- 24 to 65 inches (61 to 165 centimeters); olive gray (5Y 4/2) channery loam; 

few dark yellowish brown (10YR 3/4) pockets in the upper 6 inches; weak thick 

platy structure; very firm, brittle; few silt films on rock fragments; 25 percent 

channers and gravel; strongly acid. 

TYPE LOCATION: Newport County, Rhode Island; town of Middletown, 690 

feet north of the junction of Green End Avenue and Indian Avenue, and 160 west 

of Indian Avenue. USGS Westport, RI topographic quadrangle; Latitude 41 

degrees, 30 minutes, 33.9 seconds N. and Longitude 71 degrees, 14 minutes, 25.9 

seconds W. NAD 1927. 

RANGE IN CHARACTERISTICS: Thickness of the solum ranges from 20 

through 40 inches (50 through 100 centimeters) and typically corresponds to the 

depth to the dense substratum. Depth to bedrock is commonly more than 6 feet 

feet (2 meters). Rock fragments range from 5 through 30 percent by volume in 

the solum and from 10 through 35 percent in the substratum. Except where the 

 149 New England Soil Profiles from NEsoil.com. “Newport Series.” Established Series, Rev. RAS-EHS-DAS, March 

2010. https://soilseries.sc.egov.usda.gov/OSD_Docs/N/NEWPORT.html. Accessed October 8, 2011.
125

surface is stony, the fragments are mostly flat and less than 6 inches in diameter. 

Channers and gravel typically make up 75 percent or more of the total rock 

fragments. Unless limed, reaction ranges from very strongly acid through slightly 

acid. Low chroma colors in the B and C horizons are lithochromic. 

Some pedons have an O horizon.

The Ap horizon has hue of 7.5YR through 5Y, value of 2 through 4, and chroma 

of 1 through 3. Dry value is 6 or more. Undisturbed pedons have a thin A horizon 

with value of 2 or 3 and chroma of 1 or 2. The Ap or A horizon is silt loam, very 

fine sandy loam, loam, or fine sandy loam in the fine-earth fraction. It has weak 

or moderate granular structure and is friable or very friable. 

The Bw horizon has hue of 2.5Y or 5Y, value of 2 through 5, and chroma of 1 

through 4. Some pedons have redoximorphic features just above the Cd horizon. 

The Bw horizon is silt loam, very fine sandy loam, loam, or fine sandy loam in 

the fine-earth fraction. It has weak subangular blocky or granular structure, or the 

horizon is massive. Consistence is friable or very friable. 

The Cd horizon has hue of 2.5Y or 5Y, value of 2 through 5, and chroma of 1 

through 4. It is silt loam, very fine sandy loam, loam, or fine sandy loam in the 

fine-earth fraction. The horizon has weak or moderate, thin through thick plates, 

or it is massive. Consistence is firm or very firm. 

COMPETING SERIES: These are the Halfbluff(T) and Maggodee series. Both 

of these are from outside Region R. Halfbluff(T) does not have an OSD on file to 

compete. Maggodee soils are formed in alluvium on floodplains. 

GEOGRAPHIC SETTING: Newport soils are nearly level through moderately 

steep and are on till plains, low ridges, hills and drumlins. Slope ranges from 0 

through 35 percent. The soils formed in acid lodgement till derived mainly from 

dark carboniferous, sandstone, conglomerate, argillite, and phyllite. Mean annual 

temperature ranges from 45 through 52 degrees F. (7 through 11 degrees C.), 

mean annual precipitation ranges from 40 through 50 inches (1016 through 1270 

mm), and the growing season ranges from 135 through 185 days. 
126

Appendix I. Landfill Gas 

As waste in a landfill decomposes, it breaks down to form LFGs, such as methane, 

carbon dioxide, smog-causing volatile organic compounds (VOCs), and air toxics. 

Landfills are the third-largest anthropogenic source of methane emissions in the United 

States.150 Methane is a potent GHG that contributes to global warming. Methane is 20 

times more potent by weight than carbon dioxide. 151

Natural gas is a non-toxic, non-corrosive, and non-carcinogenic mixture of hydrocarbons, 

with methane being the largest component (approximately 83%–99%).

152 LFG has a 

much lower concentration of methane, approximately 50%, with carbon dioxide 

comprising almost all of the remaining 50%. There is a small concentration (< 1%) of 

other non-methane organic compounds.153

Landfill Emissions

Burning natural gas for energy results in lower overall emissions per unit of heat than 

coal or other fossil fuels (refined fuel oils). The average emissions rates in the United 

States from natural-gas-fired generation are: 1,135 lbs/MWh of carbon dioxide, 0.1 

lbs/MWh of sulfur dioxide, and 1.7 lbs/MWh of nitrogen oxides. Compared to the 

average air emissions from coal-fired generation, natural gas produces half as much 

carbon dioxide, less than a third as much nitrogen oxides, and 1% as much sulfur oxides 

at the power plant. In addition, the process of extraction, treatment, and transport of the 

natural gas to the power plant generates additional emissions.154

Characteristics of Landfills 

Modern landfills are designed to extract the gas created from waste decomposition and 

collect it. The captured gas may either be flared (to reduce methane migration into the 

atmosphere), combusted to provide heat or generate electricity. A cutaway schematic of a 

landfill, its collection system and flare/generator system is shown in Figure I-1.

 150 EPA. “Landfill Methane Outreach Program.” http://www.epa.gov/lmop/basic-info/index.html. Accessed October 8, 

2011.

151 EPA. “An Overview of Landfill Gas Energy in the United States.” 

http://www.epa.gov/lmop/documents/pdfs/overview.pdf. Accessed October 8, 2011. 152 DOE. “Fuel Properties.” http://www.afdc.energy.gov/afdc/fuels/properties.html. Accessed October 8, 2011. 153 EPA. “An Overview of Landfill Gas Energy in the United States.” 

http://www.epa.gov/lmop/documents/pdfs/overview.pdf. Accessed October 8, 2011. 154 EPA. “Natural Gas.” http://www.epa.gov/cleanenergy/energy-and-you/affect/natural-gas.html. Accessed October 8, 

2011.
127

Figure I-1 Landfill collection system schematic155

Characteristics of Landfill Gas Power Plants

LFG power plants, by burning the LFG, help to control LFG emissions from the landfill 

that would otherwise be released into the atmosphere and contribute to smog and global 

warming. For every 1 million tons of MSW in a landfill, approximately 432,000 ft3/day 

of LFG are created, which can be burned to generate 780 kW of electricity.156

LPG is recognized as renewable energy resource by EPA’s Green Power Partnership, the 

National Resources Defense Council and 36 states. There are at least 555 operational

LFG power plants operating in 46 states around the country. Combined these utilize 102 

billion ft3/yr of LFG and generate 14 billion kWh/yr of electricity.157

It is estimated that LFG currently provides power to 1 million homes and heating to 

737,500 homes.158

 155 EPA. “An Overview of Landfill Gas Energy in the United States.” 

http://www.epa.gov/lmop/documents/pdfs/overview.pdf. Accessed October 8, 2011. 156 EPA. “An Overview of Landfill Gas Energy in the United States.” 

http://www.epa.gov/lmop/documents/pdfs/overview.pdf. Accessed October 8, 2011. 157 Ibid. 158 EPA. “An Overview of Landfill Gas Energy in the United States.” 

http://www.epa.gov/lmop/documents/pdfs/overview.pdf. Accessed October 8, 2011.
128

Table I-1. Waste Energy Consumption159

 159 DOE EIA. “Landfill Gas.” http://www.eia.doe.gov/cneaf/solar.renewables/page/landfillgas/landfillgas.html. 

Accessed October 8, 2011.
129

Table I-2 provides a comparison of emissions from a variety of sources.

Table I-2. Emissions from Combustion Generation160

 160 DOE. “Carbon Dioxide Emissions from the Generation of Electric Power in the United States.” EPA, July 2000. 

http://www.eia.gov/cneaf/electricity/page/co2_report/co2report.html. Accessed Oct 28, 2011.
130

Appendix J. NAVSTA Newport Electric Load Data FY 2010

Table J-1. NAVSTA Newport Utility Data161

 161 Reichert, J. Email. National Grid Summary Statistics for NAVSTA Newport, Newport, RI, 4 May 2010.
131

Contacts

Project Leader

Gail Mosey

National Renewable Energy Laboratory 

1617 Cole Blvd.

Golden, CO 80401-3393 

Phone: (303) 384-7356

Fax: (303) 384-7411 

Email: gail.mosey@nrel.gov 

Principal Investigator

Robi Robichaud 

National Renewable Energy Laboratory 

1617 Cole Blvd.

Golden, CO 80401-3393 

Phone: (303) 384-6969 

Fax: (303) 384-7411 

Email: robi.robichaud@nrel.gov 

EPA Program Manager

Lura Matthews

U.S. Environmental Protection Agency

Office of Solid Waste and Emergency Response

Center for Program Analysis

Ariel Rios Building

1200 Pennsylvania Avenue, N.W.

Washington, DC 20460

Phone: (202) 566-2539

Email: matthews.lura@epa.gov

EPA Regional Manager

Ginny Lombardo

Remedial Project Manager

U.S. EPA Region I

Federal Facilities Superfund Section

5 Post Office Square

Suite 100 (OSRR 07-3)

Boston, MA 02109-3912

Phone: (617) 918-1754

Fax: (617) 918-0754 

Email: lombardo.ginny@epa.gov