Targeting Net Zero 

Energy at Fort Carson: 

Assessment and 

Recommendations

Prepared for the U.S. Department of Energy 

Federal Energy Management Program

By National Renewable Energy Laboratory

Kate Anderson, Tony Markel, Mike Simpson, 

John Leahey, Caleb Rockenbaugh, Lars Lisell, 

Kari Burman, and Mark Singer

October 2011
ii

NOTICE

This report was prepared as an account of work sponsored by an agency of the United States 

Government. Neither the United States Government nor any agency thereof, nor any of their employees, 

makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, 

completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents 

that its use would not infringe privately owned rights. Reference herein to any specific commercial 

product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily 

constitute or imply its endorsement, recommendation, or favoring by the United States Government or 

any agency thereof. The views and opinions of authors expressed herein do not necessarily state or 

reflect those of the United States Government or any agency thereof.

Printed on paper containing at least 50% wastepaper, including 20% postconsumer waste. 
iii

Contacts

Kate Anderson 

National Renewable Energy Laboratory 

Kate.Anderson@nrel.gov

303-384-7453 

Tony Markel 

National Renewable Energy Laboratory 

Tony.Markel@nrel.gov

303-275-4478 

Vince Guthrie 

Fort Carson

Vincent.Guthrie@us.army.mil

719-526-2927 
iv

Acknowledgements 

This work is sponsored by the U.S. Department of Energy (DOE) Federal Energy Management 

Program (FEMP). Richard Kidd is the FEMP Program Manager. Shawn Herrera administers the 

Technical Assistance Program. David McAndrew manages this task for FEMP. 

The authors gratefully acknowledge the assistance of Vince Guthrie, Scott Clark, and Alan Davis 

at Fort Carson for their cooperation and assistance in support of this work. We also thank Jerry 

Davis, Peter Lillienthal, Robi Robichaud, Owen Roberts, Jim Bright, Otto Van Geet, and Jesse 

Dean for their contributions to the analysis and Tim Tetreault and Dan Olis for their review of 

the report. 
v 

Abbreviations and Acronyms

AC Alternating current

AFV Alternative fuel vehicle 

AHU Air handling unit 

ARRA American Recovery and Reinvestment Act

Btu British thermal unit

C&D Construction and demolition 

CHP Combined heat and power 

CNG Compressed natural gas

CO2 Carbon dioxide 

COE Cost of energy 

CSP Concentrating solar power 

CSU Colorado Springs Utilities

CV Constant volume 

DDC Direct digital controls

DHW Domestic hot water

DoD U.S. Department of Defense

DOE U.S. Department of Energy 

DX Direct expansion

EE Energy efficiency

EEAP Energy Engineering Analysis Program 

ECIP Energy Conservation Investment Program 

ECM Energy conservation measure 

EISA Energy Independence and Security Act of 2007 

E.O. Executive order 

EPA U.S. Environmental Protection Agency 

ESCO Energy service company

ESPC Energy savings performance contract 

EUI Energy use intensity

FAR Federal Acquisition Regulation

FEMP Federal Energy Management Program 

FFRDC Federally Funded Research and Development Center 

FFV Flex fuel vehicle 

FRREC Front Range Renewable Energy Consortium 

ft2

 square foot 

GHG Greenhouse gas

GIS Geographic information system

GSA U.S. General Services Administration

GSHP Ground Source Heat Pump 

HEV Hybrid electric vehicle

HQ Headquarters 

HVAC Heating, ventilating, and air conditioning

KCF Thousand cubic feet 

kVA kilovolt-ampere

kWh kilowatt-hour 

LCOE Levelized cost of energy
vi 

LED Light-emitting diode 

MMBtu One million British thermal units

MSW Municipal solid waste 

MW Megawatt

MWe Megawatt-electrical

MWh Megawatt-hour 

NEPA National Environmental Policy Act 

NETL National Energy Technology Laboratory 

NEV Neighborhood electric vehicle 

NREL National Renewable Energy Laboratory 

NZEI Net zero energy installation

O&M Operations and maintenance

PEM Proton exchange membrane 

PNNL Pacific Northwest National Laboratory

PPA Power purchase agreement

PSD Potential for Significant Deterioration

PV Photovoltaics 

RDF Refuse-derived fuel 

REC Renewable energy certificate

SAM Solar Advisory Model 

SNL Sandia National Laboratory 

SUV Sport utility vehicle

TES Thermal energy storage 

TMP Transportation motor pool 

USNORTHCOM U.S. Northern Command 

VAV Variable air volume

VFD Variable frequency drive

W watt

WTE Waste to energy

ZEB Zero energy building
vii 

Table of Contents

1 Executive Summary................................................................................................. 1

1.1 Defining a Net Zero Energy Installation ......................................................................................... 1

1.2 Fort Carson’s Energy Baseline ........................................................................................................ 2

1.3 Energy Efficiency ............................................................................................................................ 5

1.4 Renewable Energy Analysis............................................................................................................ 6

1.5 Transportation................................................................................................................................ 7

1.6 Microgrid Analysis.......................................................................................................................... 8

1.7 Recommendations for Near Net Zero Energy Projects.................................................................. 8

1.8 Implementation............................................................................................................................ 10

1.9 Job Creation.................................................................................................................................. 11

1.10 Greenhouse Gas Savings.............................................................................................................. 11

1.11 Conclusion .................................................................................................................................... 12

2 Introduction............................................................................................................ 13

2.1 Background................................................................................................................................... 13

2.2 NZEI Concept................................................................................................................................ 14

2.3 Assessment Approach .................................................................................................................. 16

3 Fort Carson Energy Baseline................................................................................ 17

3.1 Energy Boundary .......................................................................................................................... 17

3.2 Site versus Source Energy ............................................................................................................ 17

3.3 Energy Baseline ............................................................................................................................ 18

3.4 Utility Costs .................................................................................................................................. 22

3.5 Other Energy Uses........................................................................................................................ 24

4 Reducing Energy Demand by Engaging People ................................................. 25

5 Energy Efficiency Assessment............................................................................. 27

5.1 Overview ...................................................................................................................................... 27

5.2 Planned Efficiency Projects .......................................................................................................... 29

5.3 Privatized Housing Opportunities ................................................................................................ 29

5.4 Central Energy Plant Opportunities ............................................................................................. 30

5.5 Main Base Facility Opportunities ................................................................................................. 30

6 Renewable Energy and Additional Load Reduction Projects ............................ 43

6.1 Renewable Energy Project Recommendations............................................................................ 43

6.2 Solar Ventilation Preheating ........................................................................................................ 44

6.3 Wind ............................................................................................................................................. 47

6.4 Photovoltaic (PV) Power .............................................................................................................. 49

6.5 Solar Hot Water............................................................................................................................ 54

6.6 Biomass ........................................................................................................................................ 59

6.7 Other Combined Heat and Power Options .................................................................................. 63

6.8 Concentrating Solar Power .......................................................................................................... 68

6.9 Ground Source Heat Pumps......................................................................................................... 70

6.10 Daylighting.................................................................................................................................... 73

6.11 Waste-to-Energy .......................................................................................................................... 74

6.12 Landfill Gas................................................................................................................................... 76

6.13 Anaerobic Digestion ..................................................................................................................... 77
viii

6.14 Hydropower ................................................................................................................................. 78

6.15 Additional Strategies to Reduce Load and Footprint................................................................... 78

7 Transportation Assessment.................................................................................. 79

7.1 Fleet Composition and Fuel Use................................................................................................... 79

7.2 Fleet Utilization Rates .................................................................................................................. 80

7.3 Recommendations ....................................................................................................................... 82

7.4 Other Transportation Energy ....................................................................................................... 83

8 Microgrid Assessment and Recommendations .................................................. 86

8.1 Critical Load Profile ...................................................................................................................... 86

8.2 Model Assumptions...................................................................................................................... 87

8.3 Results .......................................................................................................................................... 88

8.4 Recommendations ....................................................................................................................... 90

9 Energy Project Recommendations....................................................................... 91

9.1 Currently Cost-Effective Energy Projects ..................................................................................... 91

9.2 Net Zero Energy Projects.............................................................................................................. 91

10 Implementation: Project Planning and Financial Assessment .......................... 96

10.1 Implementation Options............................................................................................................ 96

10.2 Other Implementation Considerations ...................................................................................... 97

10.3 Financial Analysis........................................................................................................................ 98

11 Conclusion ........................................................................................................... 104

Appendix A. Electric Vehicle Grid Integration ........................................................ 105
ix

List of Figures

Figure 1. Net zero energy concept ............................................................................................................ 2

Figure 2. Fort Carson energy use breakdown (percentage of source total Btu).................................. 3

Figure 3. Actual and projected blended electric rates, 1993–2016 ........................................................ 4

Figure 4. Actual natural gas rates, 1993–2010 ......................................................................................... 4

Figure 5. 2015 energy mix ........................................................................................................................ 10

Figure 6. Boundary for Fort Carson energy baseline............................................................................ 17

Figure 7. Fort Carson energy use breakdown (percentage of source total Btu)................................ 19

Figure 8. Typical daily load profile .......................................................................................................... 20

Figure 9. Annual load profile with 2 MW PV........................................................................................... 20

Figure 10. Fort Carson projected and target EUI (kBtu/ft2) ................................................................... 21

Figure 11. Actual and projected blended electric rates, 1993–2016 .................................................... 23

Figure 12. Actual natural gas rates, 1993–2010 ..................................................................................... 23

Figure 13. 2009 Fort Carson fuel use estimates by segment ............................................................... 24

Figure 14. Modeled electricity end use for office buildings ................................................................. 33

Figure 15. Modeled electricity end use for HQ buildings...................................................................... 34

Figure 16. Modeled electricity end use for commissary....................................................................... 35

Figure 17. Modeled electricity end use for hospital .............................................................................. 37

Figure 18. Fort Carson barracks (Credit: Ian Metzger, NREL).............................................................. 38

Figure 19. Modeled electricity end use for barracks ............................................................................. 39

Figure 20. Modeled electricity end use for retail space ........................................................................ 40

Figure 21. Fort Carson solar walls (Courtesy of Fort Carson) ............................................................. 44

Figure 22. Wind resources in the Fort Carson area .............................................................................. 48

Figure 23. Fort Carson 2-MW solar array (Courtesy of Fort Carson) .................................................. 50

Figure 24. Potential rooftop and carport locations in the microgrid area........................................... 51

Figure 25. Solar hot water at Fort Carson indoor pool (Credit: John Leahey, NREL) ....................... 55

Figure 26. Microturbine units................................................................................................................... 64

Figure 27. Landfills near Fort Carson ..................................................................................................... 77

Figure 28. 2009 fleet fuel use estimates (gallons) ................................................................................. 80

Figure 29. 2009 vehicle utilization........................................................................................................... 81

Figure 30. 2009 Fort Carson fuel use estimates by segment ............................................................... 84

Figure 31. Genset fuel efficiency curve .................................................................................................. 87

Figure 32. Monthly power production for microgrid ............................................................................. 89

Figure 33. 2015 energy mix ...................................................................................................................... 93

Figure 34. Fort Carson recommended fuel use breakdown ................................................................. 95

Figure A-1. Assumed GSA vehicle adoption........................................................................................ 108

Figure A-2. The Smith Electric Newton all-electric truck, upfitted into one of many different 

configurable options (Courtesy of www.smithelectric.com) .......................................... 108

Figure A-3. Vehicle technology operational cost comparison........................................................... 109

Figure A-4. Assumed vehicle adoption trends..................................................................................... 110

Figure A-5. Starting locations for Fort Carson commuters................................................................ 111

Figure A-6. Commuter distance from Fort Carson (top) and PEV mix (bottom) .............................. 112

Figure A-7. Commuter and fleet vehicles avaiable at Fort Carson during weekdays...................... 113

Figure A-8. Base load at Fort Carson with conventional and solar generation mix during 

normal operations ............................................................................................................... 114

Figure A-9. Emergency demand and generation profile..................................................................... 115

Figure A-10. Illustration of PEV infrastructure..................................................................................... 116

Figure A-11. Opportunity charging at Fort Carson during normal operations................................. 118

Figure A-12. Opportunity charging during emergency microgrid operations.................................. 118

Figure A-13. During normal operations, both commuters and motor pool charging smoothes 

the required ramp rates for conventional generation...................................................... 119

Figure A-14. Charging at ideal times supplies plenty of range for return commutes...................... 120

Figure A-15. Controlled charging helps to slow the drop-offs in demand during normal 

operations ............................................................................................................................ 121
x 

Figure A-16. Charging smoothes the aggregated load profile during normal operations .............. 122

Figure A-17. Charge management can help buffer steep power fluctuations 

during emergency operations............................................................................................ 122

Figure A-18. Charging at ideal times supplies full range for all electric trucks 

during emergency operations............................................................................................ 123

Figure A-19. Generators receive little benefit from an electric truck fleet 

during emergency operations............................................................................................ 124

Figure A-20. V2G enabled load optimization and peak shaving during normal grid operations.... 125

Figure A-21. Charging utilizes primarily solar power while V2G offsets fossil fuels ...................... 125

Figure A-22. With V2G each commuter exchanges relatively little energy while fleet vehicles 

manage nighttime and weekend loads.............................................................................. 126

Figure A-23. V2G shaved peaks and fills valleys in the generator load profiles during normal 

operations ............................................................................................................................ 127

Figure A-24. Comparison of generation with and without PEVs exhibits their effect 

and potential benefits ......................................................................................................... 128

Figure A-25. Microgrid management of electric fleet truck V2G helps stabilize unpredictability 

of load demands and renewables supply ......................................................................... 129

Figure A-26. Electric vehicles can help maintain emergency generators at optimal operating 

conditions ............................................................................................................................. 129

Figure A-27. Battery state of charge fluctuations during emergency V2G cycle 

roughly once per day .......................................................................................................... 130

Figure A-28. V2G extended delay time and reduced overall ramping of generators 

during emergency operations............................................................................................ 131

Figure A-29. Even a small fleet of motor pool PEVs enabled gradual ramping of loads during 

emergency operations when compared with the baseline scenario.............................. 132

Figure A-30. Scalable renewable PEV energy management component for microgrids ................ 133

Figure A-31. Possible solar carport locations...................................................................................... 134
xi 

List of Tables

Table 1. Fort Carson Energy Baseline ...................................................................................................... 3

Table 2. Energy Efficiency Savings Potential .......................................................................................... 5

Table 3. Renewable Energy Technologies: Potential Energy Savings and Payback Period .............. 6

Table 4. Energy Mix to Meet the Critical Load for a Microgrid System ................................................. 8

Table 5. Near Net Zero Energy Project Recommendations .................................................................... 9

Table 6. Site-to-Source Energy Ratios,................................................................................................... 18

Table 7. Fort Carson Energy Baseline .................................................................................................... 19

Table 8. Fort Carson Projected Energy Use, 2009–2015....................................................................... 22

Table 9. Project Savings Summary ......................................................................................................... 28

Table 10. Projected Savings of Several Energy Conservation Measures........................................... 41

Table 11. Renewable Energy Technologies: Potential Energy Savings and Payback Period .......... 43

Table 12. Potential Candidates for Solar Ventilation Preheating Systems ......................................... 45

Table 13. Solar Ventilation Preheating Financial Estimate................................................................... 47

Table 14. Economic Analysis of Wind Power......................................................................................... 49

Table 15. Potential PV Capacity at Fort Carson..................................................................................... 52

Table 16. PV Systems Energy and Cost Assumptions ......................................................................... 53

Table 17. PV Economic Analysis............................................................................................................. 54

Table 18. Potential Candidates for Solar Hot Water System ................................................................ 56

Table 19. Solar Hot Water Financial Estimate........................................................................................ 58

Table 20. Biomass and Alternative Methane Fuel Resources near Fort Carson, CO ........................ 59

Table 21. Economic Analysis of Biomass CHP...................................................................................... 61

Table 22. Economic Analysis of Biomass Heat Only ............................................................................ 62

Table 23. Microturbine Analysis .............................................................................................................. 65

Table 24. Area 5 Fuel Cell Analysis......................................................................................................... 67

Table 25. CSP Energy Generation and Costs......................................................................................... 70

Table 26. Potential Energy Savings from Ground Source Heat Pumps .............................................. 72

Table 27. Daylighting Economic Analysis.............................................................................................. 74

Table 28. Economic Analysis of Waste-to-Energy Plant....................................................................... 75

Table 29. 2009 Fleet Summary by Vehicle Type and Fuel Type ........................................................... 79

Table 30. Critical Load.............................................................................................................................. 86

Table 31. Energy Mix to Meet the Critical Load...................................................................................... 89

Table 32. Cost-Effective Energy Projects............................................................................................... 91

Table 33. Recommended Projects to Achieve Near Net Zero Energy In 2015.................................... 92

Table 34. Renewable Energy Incentives................................................................................................. 98

Table 35. Initial Cost, O&M, Rebate, and REC Sale Components ...................................................... 100

Table 36. Financial Analysis of 2015 Near Net Zero Recommendations........................................... 101

Table A-1. Modeled Vehicle Characteristics......................................................................................... 107

Table A-2. Electric Truck Options Available on the 2010 GSA Schedule.......................................... 108

Table A-3. Colorado Spring Utilities' Fuel Mix, 2009 ........................................................................... 113
1 

1 Executive Summary

The U.S. Department of Defense (DoD) has long recognized the strategic importance of energy 

to its mission, and is working to reduce energy consumption, as well as to enhance energy 

security by drawing on local clean energy sources. A recent Defense Science Board report stated 

that critical military missions are at a high risk of failure in the event of an electric grid failure.1

The development of on-site renewable energy supplies can reduce this risk, and may become an 

increasingly important strategic concern. Renewable energy can also contribute to improved 

security of the energy supply and of the site, decreased or more predictable energy costs, and 

responsiveness to energy-related Federal or DoD mandates.

DoD’s U.S. Northern Command (USNORTHCOM) has partnered with the National Renewable 

Energy Laboratory (NREL) to assess opportunities for increasing energy security through 

renewable energy and energy efficiency at Front Range installations. On the basis of the 

installation’s strong history of energy advocacy and extensive track record of successful energy 

projects, USNORTHCOM selected Fort Carson to serve as the prototype installation for net zero 

energy assessment and planning. NREL performed a comprehensive assessment to appraise the 

potential of Fort Carson to achieve net zero energy status through energy efficiency, renewable 

energy, and electric vehicle integration. This report summarizes the results of the assessment and 

provides energy recommendations. 

This study is part of a larger DOE cross-laboratory effort that also includes an assessment of 

renewable opportunities at seven other DoD Front Range installations, a microgrid design for 

Fort Carson critical loads and an assessment of regulatory and market-based barriers to a 

regional secure smart grid. 

1.1 Defining a Net Zero Energy Installation

This report defines a net zero energy installation (NZEI) as follows: 

A net zero military installation produces as much energy on-site from renewable 

energy generation, or through the on-site use of renewable fuels, as it consumes in 

its buildings, facilities, and fleet vehicles.

Net zero energy is a concept of energy self-sufficiency based on minimizing demand and using 

local renewable energy resources. A complete net zero solution considers all uses of energy 

within an installation for buildings, transportation, community infrastructure, and industry. 

NREL’s net zero energy assessment for Fort Carson focused on five areas: 

1. An energy baseline

2. Energy efficiency improvements

3. Renewable energy potential

4. Electrical systems analysis

5. Transportation fuel use analysis 

 

1 More Fight Less Fuel, Defense Science Board Report. February 2008.

www.acq.osd.mil/dsb/reports/ADA477619.pdf. Accessed May 2010.
2 

Figure 1 shows the phased progression from a typical installation or community, to an 

installation that has a reduced energy load, to a renewably powered installation. 

Figure 1. Net zero energy concept

1.2 Fort Carson’s Energy Baseline

The first step in an NZEI assessment is to determine an energy baseline. The baseline provides 

an analysis of current energy consumption on base. It gives planners and managers a metric to 

measure progress against. Fort Carson’s energy baseline includes all energy use in buildings, 

facilities, and fleet vehicles on the main base. The baseline does not include energy use at Pinon 

Canyon or Turkey Creek. Table 1 shows Fort Carson’s energy baseline.

Typical 

Community

Option 0

Energy Efficiency 

and Energy 

Demand Reduction

Energy Load ($ or btu or CO2)

buildings

vehicles

industry

Maximize 

efficiency, 

minimize 

demand

Renewable 

Option 1

Renewable 

Option 2

Renewable 

Option 3

Some combination 

of options 1, 2 & 3 

meet remaining load
3 

Table 1. Fort Carson Energy Baseline 

Energy Source

2009 Energy Use

Site Energy 

(Variable units)

Site Energy 

(MMBtu)

Source Energy 

(MMBtu)

Buildings and Facilities

Electricity 164,406,919 kWh 560,956 1,569,556 

Natural Gas 1,137,540 KCF 927,095 1,012,388 

Total Building Energy Use 1,488,052 2,581,944 

Fleet Fuel

Gasoline 77,799 gallons 8,558 10,158 

Diesel 53,051 gallons 7,321 8,478 

E85 126,152 gallons 11,089 13,163 

Compressed Natural Gas 19,497 gallons 2,435 2,659 

Total Fleet Energy Use 29,403 34,458 

Total

Total Fort Carson Energy 

Use 1,517,455 2,616,402 

The total baseline energy usage at Fort Carson is 1.5 million site MMBtu, or 2.6 million source 

MMBtu. Electricity and natural gas account for most of this usage, with a small portion going to 

fleet fuel, as Figure 2 shows. 

Figure 2. Fort Carson energy use breakdown (percentage of source total Btu)

Electricity, 

60%

Natural Gas , 

39%

Fleet Fuel, 

1%
4 

Among the more important factors in determining the economic viability of investments in 

energy efficiency or renewable energy are energy costs. Figure 3 and Figure 4 show how utility 

prices are expected to change over the next six years. Colorado Springs Utilities (CSU) is 

projecting rate increases of 12%/year for 2011-2016. At this rate, electric prices would double 

from 2009’s $0.05/kWh to $0.10/kWh in 2016. 

Figure 3. Actual and projected blended electric rates, 1993–2016

Natural gas rate projections were not available, but the historical trend shows natural gas rates 

increasing from $5.44/MMBtu in 2009 to more than $9.00/MMBtu by 2016. 

Figure 4. Actual natural gas rates, 1993–2010

0 

0.02

0.04

0.06

0.08

0.1

0.12

199319941995199619971998199920002001200220032004200520062007200820092010201120122013201420152016

Blended Electric Rate ($/kWh)

Year

Actual

Projected

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

199319941995199619971998199920002001200220032004200520062007200820092010201120122013201420152016

Blended Natural Gas Rate ($/MMBTU)

Year
5 

1.3 Energy Efficiency

The second step in a net zero energy analysis is to evaluate the potential for reductions in energy 

use through improvements in energy efficiency. Through discussion with base personnel, 

analysis of previous energy audits, and modeling of typical buildings, NREL estimated the 

energy efficiency savings potential of the base. Table 2 summarizes the potential energy savings 

at Fort Carson, which totals 26.7% electrical load reduction, 17.2% natural gas load reduction, 

and 20.3% overall energy reduction. 

Table 2. Energy Efficiency Savings Potential

Measure

Savings 

(% of fuel type)

MMBtu

Equivalent 

Savings

% Total 

Site 

Savings

DHW Boiler 

Replacement

MWh - - - -

MMBtu 10,704 0.9% 10,704 0.6%

2009 Energy Assessment 

Measures

MWh 3,378 2.1% 11,529 0.7%

MMBtu 39,743 3.5% 39,743 2.3%

Privatized Housing

MWh 5,020 3.1% 17,133 1.0%

MMBtu 102,115 9.0% 102,115 6.0%

Central Heating Plants

MWh - - - -

MMBtu 43,225 3.8% 43,225 2.5%

Specific Main Base Facilities

Retail (28% reduction) MWh 371 0.2% 1,266 0.1%

Barracks (16% 

reduction) MWh 5,955 3.6% 20,324 1.2%

Hospital (38% reduction) MWh 6,420 3.9% 21,911 1.3%

Commissary (31% 

reduction) MWh 1,439 0.9% 4,911 0.3%

Headquarters (35% 

reduction) MWh 1,710 1.0% 5,836 0.3%

Office (35% reduction) MWh 1,311 0.8% 4,474 0.3%

Other (29% reduction) MWh 3,671 2.2% 1,529 0.7%

Base-Wide ECMs

Retro-commissioning MWh 8,220 5.0% 28,055 1.7%

Computer Energy Mgmt MWh 3,957 2.4% 13,505 0.8%

Occupancy Sensors MWh 2,173 1.3% 7,416 0.4%

Total

Electricity MWh 43,818 26.7% 149,550 8.8%

Natural Gas MMBtu 195,787 17.2% 195,787 11.5%

Total 

MMBtu 345,337 20.3%
6 

1.4 Renewable Energy Analysis

After assessing energy use reduction opportunities at Fort Carson, NREL evaluated the potential 

for renewable energy generation to meet energy needs that would remain after any energy 

efficiency improvements were implemented. Table 3 summarizes the renewable energy 

technologies analyzed, including size, potential energy savings, and simple payback period. 

Table 3. Renewable Energy Technologies: Potential Energy Savings and Payback Period

Technology Evaluated Size

Potential Site 

Energy 

Savings 

(MMBtu)

Potential Source 

Energy Savings 

(MMBtu)

Simple 

Payback 

Period (years)

Solar Ventilation 

Preheating 88,050 ft2 26,353 28,777 15 

Wind 10.5 MW 61,304 171,528 16

Photovoltaics (PV) 42.43 MW 216,178 604,865 26-46

Biomass Heat Only 30 MMBtu/hr 160,000 174,720 29

Solar Water 

Heating 43,441 ft2 20,887 22,809 30

Concentrating 

Solar Power (CSP) 10 MW 81,888 229,123 42

Fuel Cell 1400 kW -8,000 45,856 43

Ground Source 

Heat Pump (GSHP) 18,150 tons 378,391 178,463 57

Daylighting 770,000 ft2 35,053 38,278 147

Biomass CHP

5 MW thermal, 

7 MW electrical 283,771 452,792 Negative

Microturbine 60 kW -1,428 389 Negative 

Waste-to-Energy 

(WTE) 670 kW 15,333 42,902 Negative

Landfill Gas 0 0 0 N/A

Anaerobic 

Digestion 0 0 0 N/A

Hydro Power 0 0 0 N/A

This analysis shows that renewables currently have long payback periods at Fort Carson, due to 

the relatively low cost of fossil energy in the region. The analysis found that solar ventilation 

preheating, biomass, and solar hot water are the most cost-effective heating technologies. Wind 

and photovoltaics (PV) are the most cost-effective electric technologies. Projected increases in 

energy prices could improve the economics of renewable projects. 
7 

1.5 Transportation

The analysis evaluated options for reducing transportation energy use at Fort Carson. 

Recommendations include:

• Track fleet fuel use. Tracking allows better management of fuel use and fuel savings 

opportunities. 

• Right-size the fleet. Reduce the total number of vehicles in the fleet and allocate 

savings to other fleet needs. 

• Switch to alternative fuel vehicles. Fort Carson has done an excellent job 

incorporating alternative fuel vehicles in its fleet, but there is a potential for additional 

transportation energy savings. Nearly half of the Fort Carson fleet is fueled by 

traditional gasoline or diesel, consuming an estimated 130,000 gallons of petroleum 

annually. If Fort Carson replaced half of the gasoline vehicles with flex fuel vehicles

(FFV) that run on E85, and if personnel consistently fueled them with E85, this would 

displace nearly 40,000 gallons of gasoline consumption per year. If biodiesel were 

used consistently in the diesel vehicle fleet, Fort Carson could displace another 

10,000 gallons of petroleum per year. 

• Use alternative fuel. Always use E85 in FFVs and consider a biodiesel program for 

diesel vehicles. 

• Hybrids and electric vehicles (HEVs). Consider HEVs when other alternative fuel 

vehicle technologies are not available to meet the mission. 

• Evaluate tactical and commuter fuel use. Tactical and commuter fuel make up 97% 

of the transportation energy used on Fort Carson, dwarfing Federal fleet fuel use. If 

commuter fuel use were to be reduced by 5 percent, the resultant 350,000 gallons of 

petroleum displaced would more than exceed the fuel used by the fleet. While 

commuter and tactical fuel use was not part of this analysis, we recommend 

evaluating policies that could reduce commuter fuel use, including alternative work 

schedules and locations, staggered start times to reduce idling at the gate, and ride 

sharing. We also recommend identifying potential operational efficiencies to reduce 

tactical fuel use. 
8 

1.6 Microgrid Analysis

In this analysis, we optimized the size of each technology to find the most cost effective solution 

to meet critical loads of 3-4 MW in an islanded microgrid scenario (that is, with no grid 

connection). This scenario looked at traditional diesel generation and battery storage in addition 

to PV, wind, and biomass. Analysis found the optimal solution to be a combination 3.1 MW of 

biomass, 1 MW of diesel generation, and 500 kW of PV (see Table 4). The cost of energy (COE) 

is $0.17/kWh, compared to a diesel-only COE of $0.250/kWh. Diesel fuel use decreases 93% 

from the diesel-only solution. 

Table 4. Energy Mix to Meet the Critical Load for a Microgrid System

Component Size (MW) Production (kWh/yr) Production (%)

Biomass 3.1 23,349,642 91

Diesel Generator 1.0 1,552,869 6

PV array 0.5 778,655 3

Total 25,681,166 100

In a microgrid, the load and generation must match exactly at all times, so consistent baseload 

sources of power are preferred. The microgrid relies mainly on biomass as the cheapest 

renewable source of baseload power, and would require a large supply of off-site biomass. To 

reduce reliance on outside fuel sources such as biomass and diesel, CSP (concentrating solar 

power) with thermal energy storage could also provide consistent baseload power at a cost of 

$0.21/kWh. Forty acres of land near the microgrid area would be required. 

1.7 Recommendations for Near Net Zero Energy Projects

NREL proposed energy projects to help Fort Carson approach net zero energy. Table 5 shows the 

projects proposed to meet energy use levels forecasted for 2015. Implementation of these 

projects would provide 100% of electrical energy, 88% of thermal energy, and 57% of 

transportation energy from renewable sources. 
9 

Table 5. Near Net Zero Energy Project Recommendations

Size 

(Variable Units)

Site Energy 

(MMBtu)

Electric Energy Project Recommendations

Efficiency 26.70% 203,388

Wind 10.5 MW 61,304

PV-ground mounta

20.2 MW 100,554

PV-rooftop 24 MW 125,580

PV-carport 28.4 MW 120,046

CSP 20 MW 170,600

Total renewable electricity 

production (MMBtu) 781,472

2015 electricity use (MMBtu) 781,472

Percent of electric energy 

supplied by renewables 100%

Thermal Energy Project Recommendations

Efficiency 17.20% 266,270

Solar vent preheat 119,748 ft2 35,841

Solar hot water 59,080 ft2 28,406

Biomass heat 30 MMBtu/hr 160,000

GSHP 24,684 tons 514,611

Total renewable thermal 

production (MMBtu) 1,005,128 

2015 thermal energy use 

(MMBtu) 1,143,335

Percent of thermal energy 

supplied by renewables 88%

Transportation Energy Project Recommendations

Replace half of gasoline-fueled 

vehicles with E85 40,000 gallons 4,400

Replace diesel with biodiesel 10,000 gallons 1,380

Continue current renewable 

fuel use 126,152 gallons 11,089 

Total renewable fuel use 176,152 gallons 16,869

Total fuel use 276,499 gallons 29,403

Percent of fleet energy supplied 

by renewables 57%

a. 2 MW of the required 20.2 MW is already installed at Fort Carson
10 

Figure 5 shows the 2015 energy mix, if all recommended projects were implemented. 

Figure 5. 2015 energy mix

The simple payback for this project is 35 years. The project requires a capital investment of $842 

million. The net present value after 40 years, without Federal tax rebates, is $96 million. The 

results from this analysis illustrate that, if fossil energy prices rise as predicted, the near net zero 

energy project recommendations are likely viable over a 40 year project lifetime and would 

provide reduced energy costs to the base. This analysis is highly dependent on future fossil 

energy prices, however. If fossil energy prices increase at a lower rate than predicted, net present 

value could become negative. 

1.8 Implementation

Fort Carson has several options for implementing energy projects, including energy savings 

performance contracts (ESPC), utility energy services contracts (UESC), power purchase 

agreements (PPA), and appropriated funds. Government-owned projects funded through 

appropriations reduce contractor financing and markup fees, but require upfront capital and 

would prevent Fort Carson from receiving Federal tax incentives. Government-owned projects 

would also place an O&M burden on Fort Carson. By contrast, privately-owned projects would 

allow Fort Carson to implement renewables without any upfront capital, and with reduced O&M 

responsibility. Privately-owned projects would also allow Fort Carson to take advantage of 

Efficiency, 24%

Wind, 3%

PV-ground 

mount, 5%

PV-rooftop, 

6%

PVcarport, 

6%

CSP, 9%

Biomass Heat, 

8%

Solar Vent 

Preheat, 2%

Solar Hot Water, 

1%

GSHP, 26%

Renewable Fleet, 

1%

Non-Renewable 

Fleet, 1%

Natural Gas, 

7%
11 

Federal tax credits, although some of the money gained in tax credits may go toward contractor 

financing and markup fees. 

Federal energy projects require funding to generate results. Carefully matching available 

financing mechanisms with specific project needs can make the difference between a stalled, 

unfunded project and a successful project generating energy and cost savings. FEMP supports 

Federal agencies in identifying, obtaining, and implementing alternative financing to fund energy 

projects. 

For assistance with ESPCs, contact: 

Scott Wolf

6848 Cooper Point Road NW

Olympia, WA 98502

Phone: 360-866-9163

Fax: 360-866-9683

scott.wolf@ee.doe.gov

For UESCs, contact:

David McAndrew

Federal Energy Management Program

202-586-7722

david.mcandrew@ee.doe.gov

Karen Thomas

National Renewable Energy Laboratory

202-488-2223

karen_thomas@nrel.gov

For PPAs, contact:

Tracy Logan

Federal Energy Management Program

202-586-9973

tracy.logan@ee.doe.gov

Chandra Shah

National Renewable Energy Laboratory

303-384-7557

chandra.shah@nrel.gov

For more information about alternative financing, visit the FEMP Financing Mechanisms Web 

page at www.femp.energy.gov/financing/mechanisms.html. 

1.9 Job Creation

Implementation of all net zero energy measures identified would results in 7543 job-years, 

assuming $92,000 in initial investment is equal to one job-year. 

1.10 Greenhouse Gas Savings

Implementation of all net zero energy measures would result in a CO2 reduction of 423,951 tons 

CO2/year. 
12 

1.11 Conclusion

The NREL analysis shows that Fort Carson has the potential to make significant progress toward 

becoming a net zero energy installation. If Fort Carson implements recommended energy 

projects and savings measures, then the base could potentially achieve a 92% site Btu reduction 

and a 95% source Btu reduction. If Fort Carson achieves this status, it will set an example for 

other military installations, provide environmental benefits, reduce costs, increase energy 

security, and exceed its goals and mandates. 
13 

2 Introduction

2.1 Background

The Department of Defense (DoD) has long recognized the strategic importance of energy to its 

mission, and is working to reduce energy consumption, as well as to enhance energy security by 

drawing on local clean energy sources. A recent Defense Science Board report stated that critical 

military missions are at a high risk of failure in the event of an electric grid failure.2 Failures 

may occur as a result of malicious activities (for example, physical or cyber attacks) or due to 

blackouts on an aging electric grid infrastructure. The development of on-site renewable energy 

supplies can reduce this risk, and may become an increasingly important strategic concern.

Renewable energy can also contribute to improved security of the energy supply and of the site. 

It can decrease energy costs or make them more predictable, as well as increase the base’s 

responsiveness to energy-related Federal or DoD mandates.

In 2008 the DoD and Department of Energy (DOE) defined a joint initiative to address military 

energy use by identifying specific actions to reduce energy demand and increase use of 

renewable energy on DoD installations. In light of DoD priorities, early attention was given to 

the possibility of net zero energy military installations (NZEI), that is, installations that would 

meet their energy needs with local renewable resources. DoD’s U.S. Northern Command 

(USNORTHCOM) has partnered with the National Renewable Energy Laboratory (NREL) to 

assess opportunities for increasing energy security through renewable energy and energy 

efficiency at Front Range installations. Because of Fort Carson’s strong history of energy 

advocacy and extensive track record of successful energy projects, USNORTHCOM selected 

Fort Carson to be the prototype installation for net zero energy assessment and planning. 

NREL’s tasking was to perform a comprehensive assessment of Fort Carson’s potential to

achieve net zero energy status and provide energy project recommendations. This study is the 

first step in USNORTHCOM’s long-term objective to move installations toward energy selfsufficiency and security. The goal is for installations to be capable of meeting their own energy 

needs for up to six months in the event of a long-term utility power failure. The objectives of this 

study are to:

• Identify net zero energy opportunities at Fort Carson and provide energy project 

recommendations 

• Assess electric grid vehicle integration opportunities at Fort Carson. 

This study is part of a larger cross-laboratory effort that will also include assessing renewable 

opportunities at seven other DoD Front Range installations, a microgrid design for Fort Carson’s

critical loads, and an assessment of regulatory and market-based barriers to the development of a 

regional secure smart grid. 

 

2 More Fight Less Fuel, Defense Science Board Report. February, 2008.

www.acq.osd.mil/dsb/reports/ADA477619.pdf. Accessed May 2010.
14 

2.2 NZEI Concept

Net zero energy is a concept of energy self-sufficiency that tries to minimize energy demand and 

increase the use of use of local renewable energy resources. In principle, a net zero energy 

installation should reduce its load through conservation and energy efficiency (typically the most 

cost effective measure, one that provides the highest returns per dollar spent), then meet the 

remaining load through on-site renewable energy. Defining a net zero energy military installation 

is complicated by the need to consider―in addition to energy used by individual buildings, 

public facilities, and infrastructure―the energy used for various forms of transportation, as well 

as mission-specific energy requirements, such as tactical fuel demands. This report uses the 

following definition: 

A net zero energy military installation produces as much energy on-site from 

renewable energy generation or through the on-site use of renewable fuels, as it 

consumes in its buildings, facilities, and fleet vehicles. 

The following bullet points provide a more detailed explanation of the net zero concept and its 

components. 

• Net Zero means that the energy produced on-site over the period of a given year is 

equal to the installation’s energy demand. This implies a connection to a local power 

grid, which, in a sense, “banks” the energy. Thus on-site renewable resources, such as

solar energy systems, may produce energy greater than that used by the installation 

during the day, and then feed that excess energy into the public grid. At night, when 

the solar system is not producing energy, the installation can pull the electricity 

required from the public grid. If the installation contributes as much or more than it 

consumes, it is net zero. 

• Energy consumption may be in the form of electricity, steam, or hot water, or the 

direct use of fuel. 

• A military installation may be a contiguous area or may comprise separate areas. 

Assessments of the energy use of the installation must include all activities within the 

defined boundaries, regardless of whether their energy is managed by the base energy 

manager, or paid for by different agencies. 

• A facility is any structure on a military installation that is not a building or fleet 

vehicle, such as a swimming pool or area lighting.

• On-site energy production was a key focus for the assessment team. The team

considered both energy generated on-site from renewable sources and renewable fuel 

used on-site. The set of on-site renewable energy sources followed standard DOE 

practice: commercially available solar (photovoltaic, concentrating solar power, water 

heating, and space heating), wind, geothermal, biomass and hydropower systems, and 

electricity or heat generated from biogas produced in on-site landfills or by burning 

the installation’s solid waste (waste-to-energy). 

o Renewable fuels include various forms of biomass (wood waste, agricultural 

byproducts); natural gas produced, for example, from external landfills or as a 

byproduct of sewage processing; and various renewable transportation fuels 

(ethanol, E85, biodiesel). 
15 

o As used here, the net zero energy concept does not include non-primary 

energy imported from offsite (for example, electricity from a local offsite 

renewable source), or purchases of renewable energy certificates (RECs). This

provision is in keeping with the NZEI concepts’ emphasis on meeting energy 

needs with local resources.

• It is possible to measure energy consumption at an installation in several ways. As 

adapted from Torcellini et al.,3

 possible measurement approaches include: 

o Net Zero Site Energy. Site energy refers to energy used by the installation 

that is accounted for at the site, for example, as indicated by building 

electricity and gas meters. This approach is generally straightforward, but 

omits transmission losses to bring energy to the site. 

o Net Zero Source Energy. Source energy refers to the primary energy used to 

generate and deliver the energy to a site, for example, by a local utility 

generation and transmission system. For transportation fuel, source energy 

would include a multiplier to account for the energy required to transport the 

fuel to the fueling station. 

o Net Zero Energy Costs. This approach compares 1) the amount of money 

that the utility pays the installation for renewable energy generated on-site and 

exported to the grid with 2) the amount the installation pays the utility for 

energy used over a year. 

o Net Zero Energy Emissions. Here the installation attempts to produce on-site

at least as much renewable energy as it currently uses from offsite nonrenewable energy sources each year, thus offsetting the emissions of offsite 

energy production. 

• The project team judged net zero source energy to be the most representative measure 

of primary energy consumption, and selected it as the basis for energy accounting for 

NZEI analysis. 

• These calculations include base transportation fuel use with the following limitations:

all transportation fuel consumption data is gathered for the purpose of establishing an 

installation’s total footprint, data permitting. The total can include fuel use by Federal 

Government ground fleet vehicles, fuel associated with commercial air travel for 

official business, fuel used in personnel commuting, and tactical fuel use. However, 

only fuel use of the Federal Government fleet is addressed in the NZEI analysis.

Potential fuel reduction measures include converting to electric vehicles, using 

electricity generated on-site from renewable sources, or the use of renewable fuels in 

fleet vehicles. 

o Because the DoD’s capability to significantly affect energy used in 

commercial air travel and by commuters is limited to minimizing trips, 

encouraging carpooling or telecommuting (where possible), or providing 

electric vehicle charging stations, these categories are not considered. Tactical 

 

3 Torcellini et al. “Zero Energy Buildings (ZEB): A Critical Look at the Definition.” Golden, Colorado: National 

Renewable Energy Laboratory. 2006.
16 

fuel requirements are not addressed in the assessment since renewable fuel 

alternatives are not yet commercially available. DoD can (and does) examine 

training requirements and opportunities to use simulators instead of real 

tanks/personnel carriers, aircraft, ships and submarines. The department can

also explore logistical variations in theater that can also reduce fuel use, but 

this report does not address these options. 

Again, the net zero energy installation concept can be seen as a useful entry point into exploring 

demand reduction through human action and energy efficiency technology, and then meeting the 

remaining energy needs with local renewable energy resources. Some installations will be able to 

exceed net zero status to become net energy producers, while others will not be able to approach 

it. In fact, a net zero goal, too strictly applied, can lead to solutions that make poor sense from an

economic or other perspectives. But assessment of a site’s net zero potential, combined with 

consideration of the other constraints identified in the preceding section, provide a disciplined 

basis for identifying an optimal energy strategy that is tailored to the requirements of each site.

2.3 Assessment Approach

The approach developed for this assessment includes seven steps, which we summarize here and

then address in detail in the remaining chapters of this report.

1. Establish Fort Carson Energy Baseline. Identify the installation mission, 

geographic boundaries, and any special energy requirements (e.g., reliability, 

performance in emergency situations, etc.). Summarize annual energy used by all 

identified sources supporting the mission. 

2. Demand Reduction through Human Action. Identify approaches to minimizing 

wasted energy while maintaining or improving the quality of mission execution. 

3. Energy Efficiency Assessment. Identify specific on-site energy efficiency projects 

and their effect on installation energy consumption. 

4. Renewable Energy and Load Reduction Assessment. Identify projects exploiting 

on-site renewable energy or employing renewable fuels on-site for electricity and/or 

heat production. 

5. Transportation Assessment. Identify projects to reduce and replace fossil fuel use in 

fleet vehicles.

6. Microgrid Assessment. Outline the characteristics of a smart microgrid to support 

emergency operations in the event of a public grid outage. Identify the impacts of 

renewable energy projects on the microgrid. 

7. Energy Project Recommendations. Recommend a set of energy projects and 

implementation options. Calculate the extent to which the installation can approach 

net zero energy status. 
17 

3 Fort Carson Energy Baseline

The first step in an NZEI assessment is to determine an energy baseline. The baseline is used to 

evaluate net zero energy potential and includes energy use in on-site buildings, facilities, and 

fleet vehicles.

3.1 Energy Boundary

Working with Fort Carson staff, NREL defined the geographical boundary of the installation as 

the energy boundary for Fort Carson’s energy baseline. Figure 6 shows the energy boundary 

outlined in yellow. The majority of energy usage occurs in the developed area at the north tip of 

the installation, outlined in red. The rest of the base is mainly open land used for training 

activities. The energy baseline does not include energy use at the Turkey Creek Recreation Area 

south of the main site or the Pinon Canyon site near Trinidad, Colorado. 

Figure 6. Boundary for Fort Carson energy baseline (Credit: Billy Roberts, NREL)

3.2 Site versus Source Energy

Many people are familiar with the terms site Btu or site energy, which refers to the amount of 

fuel and electricity consumed and reflected in utility bills. However, energy may be delivered to 

a facility as either primary or secondary energy. Primary energy is raw fuel that is burned on-site

to create heat or electricity. Secondary energy is the product of the combustion of the raw fuel as 

thermal energy or electricity. It is not possible to directly compare primary with secondary 

energy because the former is a raw fuel and the latter is a product of combustion of the raw fuel. 

Utilizing source energy as the common metric for analysis, as is done within this assessment, 

permits comparison of the primary and secondary energy, and also better supports assessment of 
18 

DoD goals for fossil fuel reduction and renewable energy generation. A source energy analysis 

enables us to also account for the energy required to transport fuel to the base, as well as for

energy losses due to inefficiencies in the electrical generation process. 

For raw fuels, the difference between site and source energy is minimal. Source energy accounts 

for fuel distribution and dispensing, but not fuel production. For example, diesel fuel losses for 

fuel transport, storage, and dispensing are accounted for, but energy used in extracting crude oil 

and refining it into diesel fuel is not accounted for. The same basic analysis applies to electricity: 

losses in producing the fuel to be combusted for electrical energy production are not accounted 

for. However, the losses in the conversion of a primary chemical fuel, such as coal, to a 

secondary fuel, such as electricity, are accounted for. 

The conversion factor to translate between site and source energy for a specific installation 

depends on many factors, such as the location of the installation, the efficiency of the energy 

distribution system, and the location from which the installation’s energy is sourced. For 

example, the electrical energy conversion factor will depend on the specific power plant from 

which an installation receives its energy, the efficiency of the power plant, and the proximity to 

the installation. For this analysis we used a Colorado Springs Utilities (CSU) specific electrical 

site-to-source ratio and national ratios for natural gas, gasoline, and diesel fuel (see Table 6).We 

calculated the CSU ratio based on CSU’s generation mix and source factors for each fuel type in 

the mix. Ratios were not available for E85 or compressed natural gas, so we used the gasoline 

ratio for E85 and the natural gas ratio for compressed natural gas.

Table 6. Site-to-Source Energy Ratios4,5

Energy Type/Fuel Site-to-Source Ratio

Electricity 2.798

Natural Gas 1.092

Gasoline 1.187

Diesel Fuel 1.158

E85 1.187

Compressed Natural Gas 1.092

3.3 Energy Baseline

3.3.1 Current Energy Use

An energy baseline provides an analysis of current energy consumption on base, as well as a 

metric against which to measure progress. Table 7 shows baseline energy consumption for Fort 

Carson. 

 

4 Deru, M.; Torcellini, P. Source Energy and Emission Factors for Energy Use in Buildings. NREL/TP-550-38617. 

Golden, CO: National Renewable Energy Laboratory, June 2007. www.nrel.gov/docs/fy07osti/38617.pdf, Accessed 

June 2010. 5 CSU Sources of Generation. www.csu.org/residential/services/electricity/item854.html. Accessed June 2010. 
19 

Table 7. Fort Carson Energy Baseline

Energy Source

2009 Energy Use

Site Energy 

(Variable units)

Site Energy 

(MMBtu)

Source Energy 

(MMBtu)

Buildings and Facilities

Electricity 164,406,919 kWh 560,956 1,569,556

Natural Gas 1,137,540 KCF 927,095 1,012,388

Total Building Energy Use 1,488,052 2,581,944

Fleet Fuel

Gasoline 77,799 gallons 8558 10,158 

Diesel 53,051 gallons 7321 8478 

E85 126,152 gallons 11,089 13,163 

Compressed Natural Gas 19,497 gallons 2435 2659

Total Fleet Fuel Use 29,403 34,458

Total

Total Fort Carson Energy Use 1,517,455 2,616,402

The total baseline energy usage at Fort Carson is 1.5 million site MMBtu or 2.6 million source 

MMBtu per year. Electricity and natural gas account for most of this use, with a small portion 

going to fleet fuel, as Figure 7 shows. 

Figure 7. Fort Carson energy use breakdown (percentage of source total Btu)

Electricity, 

60%

Natural Gas , 

39%

Fleet Fuel, 

1%
20 

3.3.2 Load Profile

We based Fort Carson’s load profile on 2009 monthly utility consumption and a typical load 

profile for a weekday and a weekend day in January (obtained from the base’s recently installed 

advanced meters). Figure 8 shows the typical day load and Figure 9 depicts the annual load 

profile.

Figure 8. Typical daily load profile

Figure 9. Annual load profile with 2 MW PV

The daily load profile shows two peaks (morning hours and evening hours). The dip in 

consumption during the middle of the day is partially due to the existing 2 MW PV arrays, which 

reach peak power production at that time. The annual load profile shows an annual peak load of 

28 MW. 

3.3.3 Projected Energy Use (2010−2015)

Fort Carson expects to double its population from 15,000 to 30,000 by FY 2013 as other Army 

bases close and battalions are reassigned there. Fort Carson’s building area is expected to grow 
21 

36% over the next five years to accommodate new personnel, leading to significant growth in 

energy use. 

NREL predicted Fort Carson’s energy growth based on the base’s planned growth in total 

building area and the projected building energy use intensity (EUI). Figure 10 shows actual and 

projected EUI for 2003-2015, along with target values based on Federal mandates. The target 

EUI represents the EUI needed to meet Executive Order 134236

 and the Energy Independence 

and Security Act of 2007 (EISA)

7 while the projected EUI was extrapolated from past EUI 

performance at Fort Carson. We base our prediction of future energy use on the projected EUI, 

which provides a more conservative estimate than target EUI, and we consider it a more realistic 

indicator of future performance. 

Figure 10. Fort Carson projected and target EUI (kBtu/ft2) 

Table 8 shows actual energy use in 2009 and projected energy use for 2010-2015. We assume

that building energy use changes according to the projected building area and EUI, while energy 

use in privatized housing and Federal fleet remains constant. We predict site energy use will 

increase 27% from 2009 to 2015, and source energy use will increase 33%. The source energy 

increase is greater because electricity use increases more than natural gas, and electricity has a 

higher site-to-source ratio. 

 

6 Section 2a of Executive Order 13423 requires an energy intensity reduction of 3% annually or a 30% combined 

reduction relative to a 2003 baseline. See http://edocket.access.gpo.gov/2007/pdf/07-374.pdf. Accessed June 2010. 7 Section 431 of the Energy Independence and Security Act of 2007 requires that total energy use in Federal 

buildings, relative to the 2005 level, be reduced by 30% by 2015. See http://energy.senate.gov/

public/_files/RL342941.pdf. Accessed June 2010.

70

80

90

100

110

120

130

140

2002 2004 2006 2008 2010 2012 2014 2016

Energy Use Intensity (kBTU/Sqft)

Fiscal Year

Actual Projected Target Linear (Actual)
22 

Table 8. Fort Carson Projected Energy Use, 2009–2015

Year FY09 FY10 FY11 FY12 FY13 FY14 FY15

Military 

Construction 

Budget ($ 

millions) - $493.10 $143.60 $59.70 $148.10 $75.00 $0

Estimated New 

Building Area 

(KSF) @ 

$250/ft

2 - 1,972 574 239 592 300 0

Estimated Total 

Building Area

excluding 

housing (KSF) 10,230 12,202 12,776 13,015 13,607 13,907 13,907

Projected 

Energy Use 

Intensity 

(KBTU/SF) 119.4 120.8 120.0 119.2 118.4 117.7 116.9

Estimated 

Family Housing 

Area (KSF) 4,400 4,400 4,400 4,400 4,400 4,400 4,400

Family Housing 

Energy Use 

Intensity 

(KBTU/SF) 61.3 61.3 61.3 61.3 61.3 61.3 61.3

Fleet Fuel Site 

Energy Use 

(MMBtu) 29,403 29,403 29,403 29,403 29,403 29,403 29,403

Projected Site 

Energy

(MMBtu) 1,517,455 1,773,081 1,832,199 1,850,467 1,910,148 1,935,933 1,924,807

Projected 

Source Energy 

(MMBtu) 2,616,402 3,067,785 3,196,118 3,255,107 3,387,331 3,461,326 3,470,201

3.4 Utility Costs

FY 2009 electricity costs ranged from $0.0264-0.0313/kWh and the monthly demand charge 

varied from $11.36/kW-$14.11/kW. The blended rate averaged $0.05/kWh. Figure 11 shows 

historical and projected electric rates. CSU is projecting rate increases of 12% per year for 2010-

2016. If electric rates increase at the projected rate, prices will double from 2009’s $0.05/kWh to 

$0.10/kWh in 2016. 

The cost of fossil energy is an important factor in determining the economic viability of 

investments in energy efficiency or renewable energy. This analysis uses CSU projections for 
23 

electricity prices from 2010-2016, and a subsequent annual growth rate of 2.2% (1% above 

inflation) for 2017-2035. For natural gas price growth rates, we assume a constant 2.2% annual 

growth rate for 2010-2035. The economics of projects could change significantly if utility prices 

change at a different rate.

Figure 11. Actual and projected blended electric rates, 1993–2016

Figure 12 shows historical natural gas rates. Projected rates were not available, but 2009 rates 

were historically low, and Fort Carson expects natural gas rates to increase again in future years.

Figure 12. Actual natural gas rates, 1993–2010

0 

0.02

0.04

0.06

0.08

0.1

0.12

199319941995199619971998199920002001200220032004200520062007200820092010201120122013201420152016

Blended Electric Rate ($/kWh)

Year

Actual

Projected

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

19931994199519961997199819992000200120022003200420052006200720082009201020112012201320142015

Blended Natural Gas Rate ($/MMBTU)

Year
24 

3.5 Other Energy Uses

While not included in the energy baseline, it is important to note that significant quantities of 

tactical fuel and commuter fuel are consumed on Fort Carson. Figure 13 shows that tactical fuel 

and commuter fuel use actually make up the majority of transportation fuel use. 

Figure 13. 2009 Fort Carson fuel use estimates by segment

The amounts of fuel used for tactical operations and by commuters are outside of the control of 

the installation energy managers. Although there are opportunities for future analysis in 

examining the potential to reduce the use of fuel in training operations and commuting vehicles, 

this project did not include these uses. In addition, NREL was not able to determine the footprint 

from commercial flights taken by base personnel; however, this is another area for energy use 

analysis. 

7M

1M

0.3M

Commuter Tactical Fleet
25 

4 Reducing Energy Demand by Engaging People

Having established baseline energy use, analysts turned to the task of identifying the most 

economic ways to reduce the installation’s energy demand. There are two main approaches: 1)

identifying actions to reduce energy use without the need for capital expenditures, and 2) 

implementing energy-efficient technologies and design strategies. Identifying opportunities for 

procedural, behavioral, process, or operational energy-saving actions relies on engaging the 

attention and creativity of personnel, especially those with experience at the installation. 

Implementing energy-efficient technologies and design strategies is largely a technical exercise, 

which the next section will address.

Security, economic, and environmental objectives support a DoD-wide—and national—

transition to clean energy that we may usefully view as culture change, requiring individual 

awareness of energy costs, new habits of energy use, and continuing creative attention to ways of 

reducing energy demand. There is no silver bullet or purely technological solution to our present 

energy challenges: even with the adoption of energy efficient technologies, there is a tendency 

for energy demand to increase with growing populations and the arrival of new generations of 

energy-using devices. So in conjunction with an NZEI analysis, DoD leaders should 

institutionalize ways of engaging peoples’ ingenuity to reduce energy demand. This assessment 

does not attempt to quantify energy reductions due to behavior changes; however, the outline of 

a recommended approach follows. 

• Assess potential demand reduction. Estimate potential energy demand reductions 

from personnel actions, changes to processes, improvements to mission execution, 

and other sources (provide estimates in energy units and dollars). Create dedicated 

teams in functional areas across the installation’s operations to identify actions to 

permanently minimize energy use. Suggested actions should have a neutral effect on 

mission performance, or improve it. Consider energy use in facilities (lighting 

intensity, heating or air conditioning set points, and hours of operation), transport 

(vehicle miles, need for travel versus teleconferencing or videoconferencing), and 

mission uses (required hours of use of aircraft/ships/subs/ ground vehicles for training 

and operations). 

• Continuous improvement. Beyond the net zero energy assessment, Fort Carson can 

engage peoples’ ingenuity in saving energy on a continuing basis: 

o Institute an Energy Awareness campaign. Establish attention to energy use 

as a normal part of all activity, including planning, training, and mission 

execution. 

o Create competitions/contests/incentives for new ideas, or for reduced 

energy use. Make it a point of pride to help increase national energy 

independence through reducing dependence on energy from imported and/or 

“dirty” sources. 

o Create leadership/personnel teams to continue developing ways to save 

energy. Leading by example is a powerful influence across officer, enlisted, 

government, civilian, and contractor elements of the military team.
26 

o Implement energy scoreboards. The scoreboards would assess energy usage 

by individuals, buildings, or organizations and recognize best performers and 

practices. 

The Federal Energy Management Program has published several guides on how to conduct an 

energy awareness campaign: 

Creating an Energy Awareness Program

http://www1.eere.energy.gov/femp/pdfs/yhtp_ceap_hndbk.pdf 

Handbook from the Federal Energy Management Program on how to create an energy 

awareness program and campaign. 

Promoting Behavior Based Energy Efficiency in Military Housing

http://www1.eere.energy.gov/femp/pdfs/military_hndbk.pdf 

Handbook from the Federal Energy Management Program on promoting energy efficiency in 

military housing. 

Energy Managers Handbook 

http://www.wbdg.org/ccb/DOD/DOD4/dodemhb.pdf 

Department of Defense Handbook for energy managers that provides tools to help facility and 

installation energy managers perform their jobs more effectively by answering questions and 

illustrating best practices.
27 

5 Energy Efficiency Assessment 

5.1 Overview

After behavior change, energy efficiency is typically the most cost-effective energy project 

investment. Before conducting analysis of the renewable energy generation technologies at Fort 

Carson, we evaluated the potential for energy efficiency improvement, seeking ways to reduce 

the electrical and natural gas loads at the base. 

Fort Carson has already planned several projects to increase the efficiency of its building 

portfolio. We conducted analyses on these planned energy efficiency projects as well as further 

energy efficiency improvement potential. Since building-level energy use information was not 

available, we evaluated the proposed energy efficiency measures on a high level, using very 

general base information. Therefore, planners should not consider these figures as investment 

grade calculations; nor should they use them to determine the economics of a potential 

investment. The recommendations should be used for planning only, and for the purpose of 

identifying energy conservation measures (ECMs) for further investigation. 

It was beyond the scope of this project to conduct detailed energy audits of the approximately 

800 installation facilities at Fort Carson. However through discussion with base personnel, 

analysis of the previous energy savings performance contracts (ESPC) proposals and energy 

assessments, and a walk-through of several of the facilities on base we were able to estimate the 

savings potential for energy efficiency investment at the base. Using energy models and 

spreadsheet calculation tools developed at NREL, we modeled 66% of the electrical load and 

70% of the natural gas load and analyzed them for energy efficiency measures. It would be 

difficult to model the remaining energy use without an in-depth energy assessment, due to the 

distributed nature of the site and the specialty uses of various facilities. 

Table 9 summarizes the savings estimates, which the following sections explain in more detail. 

We estimate 26.7% potential electricity savings, 17.2% natural gas savings, and 20.3% overall 

savings. 
28 

Table 9. Project Savings Summary

Measure

Savings (% of 

fuel type)

MMBtu

Equivalent 

Savings

% Total 

Site 

Savings

DHW Boiler 

Replacement

MWh - - - -

MMBtu 10,704 0.9% 10,704 0.6%

2009 Energy 

Assessment 

Measures1

MWh 3,378 2.1% 11,529 0.7%

MMBtu 39,743 3.5% 39,743 2.3%

Privatized Housing

MWh 5,020 3.1% 17,133 1.0%

MMBtu 102,115 9.0% 102,115 6.0%

Central Heating 

Plants

MWh - - - -

MMBtu 43,225 3.8% 43,225 2.5%

Specific Main Base Facilitiesa

Retail (28% 

reduction) MWh 371 0.2% 1,266 0.1% 

Barracks (16% 

reduction) MWh 5,955 3.6% 20,324 1.2%

Hospital (38% 

reduction) MWh 6,420 3.9% 21,911 1.3%

Commissary (31% 

reduction) MWh 1,439 0.9% 4,911 0.3%

Headquarters (35% 

reduction) MWh 1,710 1.0% 5,836 0.3%

Office (35% 

reduction) MWh 1,311 0.8% 4,474 0.3%

Other (29% 

reduction) MWh 3,671 2.2% 1,529 0.7%

Base-Wide ECMs

Retro-commissioning MWh 8,220 5.0% 28,055 1.7%

Computer Energy 

Mgmt MWh 3,957 2.4% 13,505 0.8%

Occupancy Sensors MWh 2,173 1.3% 7,416 0.4%

Total

Electricity MWh 43,818 26.7% 149,550 8.8%

Natural Gas MMBtu 195,787 17.2% 195,787 11.5%

Total MMBtu 345,337 20.3%

a. We have reduced estimated savings for specific main base facilities, as indicated, to 

exclude heat plant measures. NREL re-evaluated heating plant savings and included the 

data separately. 
29 

5.2 Planned Efficiency Projects

5.2.1 DHW Boiler Replacement 

Fort Carson was recently awarded American Recovery and Reinvestment Act (ARRA) funding 

for a proposal to replace several of its hot water boilers throughout the base. The total projected 

savings are 10,704 MMBtu of natural gas, which represents 1% of the total baseline natural gas 

consumption of Fort Carson. 

5.2.2 2009 Energy Assessment 

In August, 2009, the Energy Engineering Analysis Program (EEAP) conducted an energy 

assessment. The EEAP assessment contained a variety of energy savings opportunities and 

contained many advisable ECMs. 

The potential energy savings from the 2009 EEAP report with the exclusion of central heating 

plant measures is 3,378 MWh/year electric and 39,743MMBtu/year natural gas. These figures 

represent 2% reduction in electrical usage and 3% reduction in natural gas usage, equivalent to 

just over a 3% total site energy reduction. The central heating plant measures are evaluated 

separately in section 5.4. 

5.3 Privatized Housing Opportunities

There are approximately 3,060 housing units for members of the military and their families on 

the main base of Fort Carson. The houses were built over a 50 year period, and have substantial 

differences in construction, mechanical systems, occupancy, and resident behavior. In order to 

estimate the energy savings associated with the housing, NREL used a residential energy 

modeling program called BeOpt.8 With input from the housing contractor, we developed a model 

of a representative two-story, 1,600 square foot house. 

BeOpt found the following energy efficiency improvements to be cost effective: 

• Install programmable thermostats to save on heating and cooling 

• Install low-flow faucets, shower heads, and toilets 

• Decrease ventilation level

• Use seasonal natural ventilation

• Add insulation to the walls, attic, and slab 

• Replace existing windows with high performance low-e windows

• Use interior shading to reduce cooling load in the summer 

• Replace all lighting with florescent technology 

• Replace current boiler with high efficiency boiler 

• Replace current DHW heater with a gas tankless heater. 

We calculated an 18% electricity reduction potential for the average-size housing unit. Applying 

this reduction potential to all of the housing units at Fort Carson equates to5,020,000 kWh/year. 

 

8 For more information on BeOpt, see: www.nrel.gov/buildings/energy_analysis.html#beopt
30 

We calculated the natural gas reduction potential to be 45% for the average size housing unit. 

Applying this reduction to all of the housing units at Fort Carson equates to 102,115 

MMBtu/year. 

Other typical housing ECMs that could potentially be implemented, but were not investigated by 

the NREL team include: 

• Switch out any non-ENERGY STAR® appliances 

• Encourage residents to save energy with energy awareness campaign and incentives 

• Reduce irrigation use 

• Turn off the power and gas to unoccupied homes to eliminate standby losses. 

5.4 Central Energy Plant Opportunities

The central heating plants generate steam and hot water to heat approximately 30% of the 

buildings on base. Energy use at the central plants represents 17.4% of the total base electrical 

load and 19.9% of the total base natural gas load. 

Analysts developed an hourly simulation model in an effort to document and capture hourly 

seasonal effects with different potential heating plant measures in place. ECMs in the energy 

model include: 

• Outdoor air-temperature-based seasonal HW temperature reset schedules

• Variable flow pumping 

• Demand-based scheduling

• Reduced distribution losses. 

The potential energy saving with the implementation of these measures in the central heating 

plants is 43,225 MMBtu/year in natural gas, representing 7% of the plant and 3% of the total site 

energy. 

Additional ECMs that could be implemented but were not investigated include: 

• Central plant recommissioning 

• Boiler stack economizers 

• Central plant annual O&M program to keep boilers running efficiently. 

• Lighting measures. 

5.5 Main Base Facility Opportunities

The main base facilities represent the vast majority of the energy use at Fort Carson, 74.7% of 

the total electrical load and 30% of the total natural gas load. We developed recommendations to 

reduce energy usage in these facilities. Section 5.5.1 discusses energy conservation measures 

recommended for specific building types, and Section 5.5.2 discusses measures recommended 

base wide for all building types. 
31 

5.5.1 Conservation Measures by Building Type

The NREL team evaluated several specific categories of buildings. These included: 

• Offices

• Headquarters (HQ) buildings 

• Commissary

• Hospital 

• Barracks

• Retail space

• Other. 

NREL spoke with the on-site staff about the base buildings, but did not visit the buildings. The 

team built basic energy models using typical building-type information and bundled ECMs to 

estimate the energy that could be saved in each building type. ECMs that we evaluated included: 

• Chillers. Many of the current facilities at Fort Carson are operating moderately 

efficient chillers. We recommend all facilities be analyzed for more efficient chiller 

upgrades. 

• Air Handling Units. According to the on-site staff, 70% of the air handling units 

(AHUs) at Fort Carson are constant volume (CV) systems and 30% are variable air 

volume (VAV). Upgrading the CV units to VAV systems would save energy by 

reducing the amount of air to be either heated or cooled. We recommend the base 

evaluate its AHUs and upgrade units to VAV models where appropriate. 

• Distributed Boilers. The efficiency of the boilers at Fort Carson varies. Some of the 

boilers are very efficient while, for others, replacement could save a substantial 

amount of energy. We recommend examination of the boilers not already scheduled 

for replacement in the retrofits funded by the American Reinvestment and Recovery 

Act (ARRA.) Technicians should examine boilers with efficiencies less than 85% for 

replacement potential with high efficiency boilers that can reach up to 95% 

efficiency. Factors to consider include expected time to replacement of existing 

boilers, as well as required supply and return water temperatures. Note that 95% 

efficiency systems are available with condensing boilers, but require low-return water 

temperatures that are not applicable for all applications.

• ENERGY STAR Refrigerators. Replacing refrigerators on the main base with 

Energy Star models could realize significant energy savings. It is assumed that small 

refrigerators are located in each of the barracks units and office buildings. Savings 

would vary by model being replaced, but would reach about 50–200 kWh per year for 

each refrigerator. 

• Controls. According to on-site staff, 180 of the 800 buildings on the base have direct 

digital controls (DDC) and are connected to the central control system. There are 

plans to add an additional 27 buildings to the system using ARRA funds. All 

buildings that have HVAC systems should be added to the central DDC system. 
32 

These actions will allow the implementation of base-wide set points and night time 

setbacks, as well as optimization of system operation. A central DDC system could 

potentially save a significant amount of energy. Some of the potential control 

upgrades follow: 

o Boiler optimization

o Chiller optimization (chilled water reset and sequencing)

o Cooling tower optimization (recommendation to only run as many fans as

needed to meet condenser water setpoint) 

o DDC controls 

o Electric demand limiting

o Static pressure setpoint 

o Mixed air dampers, for economizer 

o Night setback

o Night purge (night pre-cooling of building) 

o Occupancy sensor control

o Lighting scheduling (centralized lighting control)

o Optimal start/stop HVAC systems

o Outdoor air reduction

o Supply air reset

o VAV and variable pumping. 

• Hybrid Evaporative Cooling Roof Top Units. Many of the smaller buildings at Fort 

Carson are currently conditioned by standard roof top units. These units utilize a 

direct expansion (DX) refrigeration cycle to achieve cooling for the building. It is 

recommended that the site replace the standard DX roof top units with hybrid indirect 

evaporative cooling units. These units operate on a system that utilizes both 

evaporative cooling and the traditional refrigeration cycle. Indirect evaporative 

cooling is able to cool the space without adding any humidity to the conditioned air. 

Climate data show that Fort Carson is in a suitable location for hybrid evaporative 

cooling in its small commercial buildings. Tests performed at NREL demonstrate the 

potential for 75% savings in cooling energy when using this type of unit in place of a 

standard DX cooler. Fort Carson has many small commercial buildings, office 

buildings, and housing units that could be appropriate for this recommendation. These 

units work best in small- to medium-size buildings; therefore NRELs recommends 

that the larger facilities continue to utilize centralized chillers. The analysis for this 

ECM was performed based on products and technologies developed by the Coolerado 

Corporation. 

The sections that follow describe the energy models for each specific building type along with 

the recommended ECMs. 
33 

Offices

The main base at Fort Carson contains more than 644,000 sq. ft of office space. The average size 

of an office building is 8,157 square feet. Offices make up 5.7% of the total installation building 

square footage. Office space consumes an estimated 3,781 MWh per year of electrical energy or 

2.3% of the total base usage. The offices do not consume any natural gas directly; however they 

receive heat from the central steam distribution line for heating. The NREL team created an 

eQuest energy model of the average office building to estimate the energy reduction potential of 

the offices at Fort Carson. Figure 14 shows the modeled energy use of the office buildings. 

Figure 14. Modeled electricity end use for office buildings

NREL included the following ECMs in the energy model to estimate potential energy savings in 

the office buildings. 

• Implement a nighttime and weekend setback on the HVAC system. 

• Close the outside air dampers during unoccupied hours. 

• Enable airside economizer operation. 

• Replace the existing HVAC system with an indirect evaporative cooling system. 

The energy reduction potential was calculated to be 35% for the average size office building, or 

1,311,000 kWh/yr installation-wide. 

There are additional office ECMs, which could potentially be implemented, however, the NREL 

team did not investigate them. These include: 
34 

• Reduce lighting levels, use LED task lighting. Install occupancy sensors in most 

spaces. 

• Replace all existing faucets and toilets with low flow devices. 

• Put all offices on the central DDC system. 

HQ Buildings

The main base of Fort Carson contains more than 1,926,000 sq. ft. of headquarters (HQ) 

buildings. The average building size is 12,588 square feet. HQ buildings make up 17% of the 

total square footage of installation buildings. The HQ space consumes an estimated 4,932 MWh 

per year of electrical energy, or 3.0% of the total base usage. The HQ buildings do not consume 

any natural gas directly; however they do receive heat from the central steam distribution line for 

heating. Figure 15 shows the modeled energy use of the HQ buildings. 

Figure 15. Modeled electricity end use for HQ buildings 

The NREL team included the following ECMs in the energy model to estimate potential energy 

savings in the HQ buildings. Implement a nighttime and weekend setback on the HVAC system. 

• Close the outside air dampers during unoccupied hours. 

• Enable airside economizer operation. 

• Replace the existing HVAC system with an indirect evaporative cooling system. 
35 

We calculated the energy reduction potential to be 35% for the average size HQ building. 

Applying this reduction potential to all of the HQ buildings at Fort Carson equates to 1,710,000 

kWh/yr. 

There are additional ECMs, which could potentially be implemented, however, the NREL team

did not investigate them. These include: 

• Reduce lighting levels, use LED task lighting 

• Install occupancy sensors in most spaces

• Replace all existing faucets and toilets with low-flow devices 

• Put all HQ buildings on the central DDC system. 

Commissary

The commissary is an on-base grocery store that provides goods and services to military 

personnel and their families. The commissary comprises 0.9% of the total installation building 

square footage. The commissary uses an estimated 4,603 MWh per year of electrical energy, or 

2.8% of the total base usage. The commissary does not directly use any natural gas; however, it 

does receive heat from the central steam distribution line for heating. Figure 16 shows the 

modeled energy use of the commissary. 

Figure 16. Modeled electricity end use for commissary
36 

Our analysis included the following ECMs in the energy model to estimate potential energy 

savings in the HQ buildings: 

• Implement a nighttime and weekend setback on the HVAC system 

• Close the outside air dampers during unoccupied hours 

• Enable airside economizer operation

• Convert the system from a constant volume system to a VAV system

• Implement static pressure reset 

• Replace the current chiller with a high efficiency variable speed chiller

• Put a variable frequency drive (VFD) on the cooling tower fan 

• Implement a condenser water temperature reset

• Install chiller water temperature reset

• Put a VFD on the chilled water pumps. 

Bundling these measures could provide the commissary with the potential to save 1,439,000 

kWh, which would represent a 31% reduction in the electrical load of the commissary. 

There are additional food sales ECMs that could potentially be implemented; however, the 

NREL team did not investigate them. These include: 

• Lighting level reduction. 

• Switching the light bulbs in freezers and refrigerators to LED bulbs to save on both 

cooling and lighting energy. The heat produced by standard bulbs increases energy 

requirements for the freezers by 25-50%.9

• Utilize waste heat from refrigeration to reduce its heating load requirements. (The 

heating load is estimated to comprise 15% of the energy use in an average food sales 

store.) 

• Put the commissary on the central DDC system. 

Hospital

The on-base hospital provides medical care to military personnel and their families. The hospital 

comprises 4.6% of the total installation building square footage. The hospital consumes an 

estimated 15,947 MWh per year of electrical energy or 9.7% of the total base usage. Although 

the hospital does not consume any natural gas directly, it does receive heat from the central 

steam distribution line for heating. Figure 17 shows the modeled energy use of a hospital. 

 

9 “Lighting The Way to Greener Retail”, Nualight. www.nualight.ie/lighting_the_way_to_greener_retail.pdf
37 

Figure 17. Modeled electricity end use for hospital 

The NREL team included the following ECMs in its energy model to estimate the potential 

energy savings in the hospital: 

• Set the OA to the minimum value during the night 

• Enable airside economizer operation

• Convert the system from a constant volume system to a VAV system 

• Implement duct static pressure reset

• Replace the current chiller with a high-efficiency variable speed chiller

• Put a VFD on the cooling tower fan 

• Implement a condenser water temperature reset

• Install chiller water temperature reset

• Put a VFD on the chilled water pumps. 

Bundling these measures, the hospital has the potential to save 6,420,000 kWh/year, which 

represents a 38% reduction in the electrical load of the hospital. 

Other typical hospital ECMs could be implemented; however, the NREL team did not investigate 

them. These include: 
38 

• Lighting level reduction

• Occupancy sensors 

• Replace all appliances with ENERGY STAR appliances 

• Replace existing faucets, showers, and toilets with low-flow devices 

• Utilize waste heat from the chillers to reduce the water heating and space heating load

• Put the hospital on the central DDC system. 

Barracks

Fort Carson’s barracks provide housing for the enlisted service members on the base. There are 

more than 3,253,000 square feet of barracks and similar housing at Fort Carson. The average 

building size is 35,361 square feet. Barracks and similar housing comprise 29% of the total 

installation building square footage. The barracks use an estimated 36,333 MWh per year of 

electrical energy or 22.1% of the total base usage. Although the barracks do not consume any 

natural gas directly, they do receive heat from the central steam distribution line for heating. 

Figure 18 shows a typical barracks building at Fort Carson, and Figure 19 shows the modeled 

energy use of the barracks.

Figure 18. Fort Carson barracks (Credit: Ian Metzger, NREL) 
39 

Figure 19. Modeled electricity end use for barracks

NREL included the following ECMs in the energy model in order to estimate the potential 

energy savings in the barracks: 

• Replace the air cooled chiller with a high-efficiency water-cooled chiller 

• Enable airside economizer operation

• Implement a variable flow chilled water system

• Reduce plug loads by implementing all ENERGY STAR appliances.

The analysis calculated an energy reduction potential of 16% for the average-size barrack.

Applying this reduction potential to all of the barracks at Fort Carson equates to 5,955,000 

kWh/yr. 

Other ECMs potentially could be implemented in the barracks; however, the NREL team did not 

investigate them. These include: 

• Replace washer and dryer with ENERGY STAR appliances

• Install low-flow faucets, showerheads, and toilets

• Install occupancy monitoring devices such as card readers to ensure that nonoccupied units are not being heated or cooled. 

Retail Space 

Retail space comprises 1.8% of the total installation building square footage. The on-base retail 

shops consume an estimated 1,315 MWh per year of electrical energy. Although the retail shops 
40 

do not directly use any natural gas, some receive heat from the central steam distribution line for 

heating. The retail space represents 0.8% of total base electrical energy consumption. Figure 20

shows the modeled energy use of a retail store. 

Figure 20. Modeled electricity end use for retail space

NREL included the following ECMs in the energy model to estimate the potential energy savings 

for the base’s retail space: 

• Implement a night time and weekend setback on the HVAC system

• Close the outside air dampers during unoccupied hours 

• Enable airside economizer operation

• Replace the existing HVAC system with an indirect evaporative cooling system. 

Bundling these measures, the base retail stores have the potential to save 371,000 kWh year,

which represents a 28% reduction in the electrical load. 

Other retail store ECMs potentially could be implemented; however, the NREL team did not 

investigate them. These include: 

• Reduce lighting levels 

• Utilize lighting controls for nighttime and weekend setbacks 

• Install occupancy sensors in the restrooms

• Install low-flow faucets and toilets. 
41 

Other Similar Building Types 

The structures grouped under other similar building types were those buildings that did not fit into 

any of our specific classifications. Nonetheless, they were similar enough to permit us to 

extrapolate the calculated savings from the specific building types and apply them to these other

buildings, enabling us to include them in the analysis. The other similar building types consume 

an estimated 12,824 MWh per year of electrical energy. This equates to 7.8% of total base 

electrical energy consumption. The extrapolation yielded the potential to save 3,761,000 

kWh/year, which represents a 29% reduction in the building load. 

5.5.2 Base-Wide ECMs

This section describes ECMs that apply base-wide, regardless of building type. 

Retro-Commissioning of All Mechanical Systems 

The assessment team recommends that the entire base be retro commissioned, building by 

building. Rather than replacing systems, retro commissioning involves going through all of the 

existing mechanical systems of a building, verifying operation and optimizing all functions. 

Commissioning can resolve operating problems, improve occupant comfort, and reduce energy 

use. The American Council for an Energy Efficient Economy estimated that retro commissioning 

could save 5-20% of building energy consumption.10

Plug Loads

NREL utilized its screening tools to estimate the potential for plug load reduction at Fort Carson. 

According to the on-site staff, most vending machines on the base had been retrofitted with 

ENERGY STAR vending machines. However, 105 five non-ENERGY STAR vending 

machines, however, continue to operate. These machines should be converted to ENERGY 

STAR models as the vending machine contracts come up for renegotiation. Additionally, base 

personnel stated that no computer power management programs were utilized. The assessment 

estimated the savings of measure including as installing vending machine misers, de-lamping 

105 vending machines, and utilizing power management software on 8,000 computers (4,000 

desktop, 4,000 laptop). Table 10 shows the projected savings from these measures. The majority 

of the savings come from the computer management program. 

Table 10. Projected Savings of Several Energy Conservation Measures

Plug Load 

ECM# Energy Conservation Measure

Annual Energy 

Savings (kWh/yr)

1.1 Install Vending Machine Misers 147,168

1.2

De-Lamp Vending Machine 

Advertising Lighting 45,990

1.3

Activate Computer Power 

Management 3,957,277

Totals 4,150,435

 

10 Thorne, J.; Nadel, S. “Retrocommissioning Program Strategies to Capture Energy Savings in Existing Buildings.” 

American Council for an Energy Efficient Economy. June 2003. www.aceee.org/research-report/a035
42 

Install Occupancy Sensors in Office Spaces, Work Spaces, and Bathrooms

There are only a few working occupancy sensors currently installed in the office buildings at 

Fort Carson. Occupancy sensors can save considerable energy by turning off lights when spaces 

are unoccupied. Large cubicle workstation areas, conference rooms, private offices, and 

restrooms comprise the majority of the lighting load in a typical office building. It is likely that 

many of these areas are intermittently occupied or vacant throughout the course of the day, 

creating a potential for realizing energy savings by installing occupancy sensors.

We recommend installing ceiling-mounted infrared occupancy sensors to automatically activate 

and deactivate space lighting circuits based on occupancy. This measure will not reduce peak 

demand but will reduce annual energy consumption. This measure would result in an estimated 

energy savings of 2,172,802 kWh/yr. Our assumptions include: 

• Lighting accounts for 20% of the total non-residential electric use for the buildings on 

site

• 80% of the lighting was appropriate for occupancy sensor control 

• 10% of the lighting energy savings is due to occupancy sensors.11

Exterior Lighting

Upgrades to exterior lighting at the base have not been considered high priority at Fort Carson, 

due to the fact that the base pays a very low electrical rate at night. This circumstance makes 

exterior lighting projects difficult to justify based on cost savings alone. There are several 

exterior LED lighting demonstration units in use, but there is currently no plan to expand the 

LED exterior lighting fixtures. Therefore this report does not estimate savings from exterior 

lighting upgrades. 

 

11 American Society of Heating, Refrigerating, and Air Conditioning Engineers (ASHRAE) Standard 90.1
43 

6 Renewable Energy and Additional Load Reduction Projects 

6.1 Renewable Energy Project Recommendations

After reducing energy use through conservation measures, renewable energy measures meet the 

remaining energy needs of an NZEI. Table 11 summarizes the renewable energy technologies 

analyzed, including evaluated size, potential energy savings, and simple payback period. 

Analysts based all payback periods on 2009 energy prices. The sections that follow present a

detailed analysis of each technology. 

Table 11. Renewable Energy Technologies: Potential Energy Savings and Payback Period

Technology Evaluated Size

Potential 

Site Energy 

Savings 

(MMBtu)

Potential 

Source 

Energy 

Savings 

(MMBtu)

Simple 

Payback 

Period 

(years)

Solar Ventilation 

Preheating 88,050 ft

2 26,353 28,777 15

Wind 10.5 MW 61,304 171,528 16

Photovoltaics (PV) 42.43 MW 216,178 604,865 26-46

Biomass Heat Only 30 MMBtu/hr 160,000 174,720 29 

Solar Water 

Heating 43,441 ft

2 20,887 22,809 30

Concentrating 

Solar Power (CSP) 10 MW 81,888 229,123 42

Fuel Cell 1400 kW -8,000 45,856 43

Ground Source 

Heat Pump 

(GSHP) 18,150 tons 378,391 178,463 57

Daylighting 770,000 ft2 35,053 38,278 147

Biomass CHP

5 MW thermal, 

7 MW electrical 283,771 452,792 Negative

Microturbine 60 kW -1,428 389 Negative

Waste-to-Energy 

(WTE) 670 kW 15,333 42,902 Negative

Landfill Gas 0 0 0 N/A

Anaerobic 

Digestion 0 0 0 N/A

Hydro Power 0 0 0 N/A
44 

6.2 Solar Ventilation Preheating

6.2.1 Technology Overview

Solar ventilation air preheating is a very simple, yet efficient technology. The system consists of 

metal siding perforated with small holes, mounted on the south side of a building. The sun heats 

the metal plate and that heat is added to ventilation air drawn through the holes by means of a 

fan. In summer, a by-pass damper on the face of the wall admits fresh air without heating. 

Savings at the site depend on both the solar resource and the heating degree days. Solar vent 

preheat works very well in the Front Range’s cold, sunny climate on buildings with large 

ventilation requirements. It is most often used on industrial buildings with open indoor spaces 

(not highly partitioned) and high ventilation requirements, including hangars, maintenance 

shops, and gymnasiums. 

6.2.2 Existing or Planned Projects

Fort Carson currently has solar walls installed on two vehicle maintenance buildings (8030 and 

9633), as Figure 21 shows. 

Figure 21. Fort Carson solar walls (Courtesy of Fort Carson) 

6.2.3 Analysis

Table 12 identifies additional opportunities for solar ventilation preheating. The identified

buildings appear to be good candidates based on building orientation and building type. 
45 

Table 12. Potential Candidates for Solar Ventilation Preheating Systems

Building 

Number Building Type

Building 

Size (ft2)

Estimated SVP 

size (ft2)

Annual Heating 

Savings (MMBtu/yr)

9604 AC MAINT HGR 41,062 3,647 1,092

9604 AC MAINT HGR 44,281 3,788 1,134

9604 AC MAINT HGR 13,671 2,105 630

9604 AC MAINT HGR 1,626 726 217

9604 AC MAINT HGR 1,635 728 218

9620 AC MAINT HGR 41,476 3,666 1,097

8110 ARNG VEH MAINT 26,340 2,921 874

2427 AUTO SKILL CTR 29,531 3,093 926

1525 COMMISSARY 101,725 5,741 1,718

500 FIRE STATION 4,660 1,229 368

9600 FIRE STATION 3,885 1,122 336

1805 MAIN FIRE STATION 17,000 2,347 702

749 MNT GEN PURPOSE 19,536 2,516 753

2031 MNT GEN PURPOSE 2,500 900 269

8000 MNT GEN PURPOSE 184,344 7,728 2,313

8009 PAINT/PREP SHOP, VEH 2,500 900 269

9271 PHY FITNESS CENTER 2,000 805 241

1160 PHYS FIT CTR 20,375 2,569 769

1661 PHYS FIT CTR 13,280 2,074 621

1662 PHYS FIT CTR 2,715 938 281

1662 PHYS FIT CTR 3,371 1,045 313

1843 PHYS FIT CTR 17,502 2,381 713

1856 PHYS FIT CTR 23,159 2,739 820

2357 PHYS FIT CTR 24,895 2,840 850

1829 RECREATION CTR 24,626 2,825 845

9655 TUAV HANGAR 3,876 1,121 335

7470 TUAV HANGER 4,800 1,247 373

8930 USAR VEH MAINT 11,988 1,971 590

501 VEH MAINT SHOP 34,877 3,362 1,006

633 VEH MAINT SHOP 4,806 1,248 373

633 VEH MAINT SHOP 2,406 883 264

634 VEH MAINT SHOP 4,812 1,249 374

635 VEH MAINT SHOP 4,812 1,249 374

636 VEH MAINT SHOP 4,812 1,249 374

746 VEH MAINT SHOP 5,040 1,278 382

1382 VEH MAINT SHOP 23,575 2,764 827
46 

1392 VEH MAINT SHOP 23,575 2,764 827

1682 VEH MAINT SHOP 27,175 2,967 888

1692 VEH MAINT SHOP 23,575 2,764 827

1882 VEH MAINT SHOP 21,935 2,666 798

1982 VEH MAINT SHOP 15,470 2,239 670

2082 VEH MAINT SHOP 23,703 2,771 829

2392 VEH MAINT SHOP 23,575 2,764 827

2492 VEH MAINT SHOP 23,575 2,764 827

2605 VEH MAINT SHOP 51,617 4,089 1,224

2615 VEH MAINT SHOP 51,617 4,089 1,224

2625 VEH MAINT SHOP 51,617 4,089 1,224

2635 VEH MAINT SHOP 51,617 4,089 1,224

2645 VEH MAINT SHOP 51,617 4,089 1,224

2655 VEH MAINT SHOP 51,617 4,089 1,224

2692 VEH MAINT SHOP 23,575 2,764 827

2792 VEH MAINT SHOP 23,575 2,764 827

2992 VEH MAINT SHOP 23,575 2,764 827

3092 VEH MAINT SHOP 23,575 2,764 827

3192 VEH MAINT SHOP 23,575 2,764 827

3292 VEH MAINT SHOP 23,575 2,764 827

7426 VEH MAINT SHOP 16,386 2,304 690

7467 VEH MAINT SHOP 34,306 3,334 998

8030 VEH MAINT SHOP 50,750 4,055 1,214

8142 VEH MAINT SHOP 45,200 3,827 1,145

8152 VEH MAINT SHOP 23,298 2,747 822

8200 VEH MAINT SHOP 16,881 2,339 700

8300 VEH MAINT SHOP 15,715 2,256 675

8300 VEH MAINT SHOP 650 459 137

8300 VEH MAINT SHOP 24,490 2,817 843

9072 VEH MAINT SHOP 28,362 3,031 907

9277 VEH MAINT SHOP 4,000 1,138 341

9277 VEH MAINT SHOP 4,000 1,138 341

9628 VEH MAINT SHOP 12,737 2,031 608

9628 VEH MAINT SHOP 8,934 1,701 509

20001 VEH MAINT SHOP 3,811 1,111 333

Total 176,100 52,707
47 

For the net zero analysis, we assume that half of these installations will be viable sites, resulting 

in a total of 88,050 square feet of solar ventilation preheat area and 26,353 MMBtu of annual 

energy savings. 

6.2.4 Economic Analysis

Table 13 estimates the costs of installing solar ventilation preheating systems on these buildings. 

Table 13. Solar Ventilation Preheating Financial Estimate

Solar Vent Preheat Area (ft2) 88,050

Initial Cost ($) $2,241,277

Rebates & Incentives 0

Annual Gas Savings (MMBtu/yr) 26,353

Annual Utility Cost Savings ($/yr) $145,857

Payback Period (yr) 15.4

6.2.5 Recommendation

Solar ventilation preheating systems are one of the most cost-effective renewable energy 

technologies available to Fort Carson. We recommend installing additional solar ventilation 

preheating systems wherever feasible, putting a priority on motor pools, hangars, and heat plant. 

6.3 Wind

6.3.1 Technology Overview

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

power. They contain several moving parts and require regularly scheduled and unscheduled 

maintenance. Turbines range from as small as 250 W to as large as 5 MW. The larger wind 

turbines are the most economical. Wind turbines work best when installed in areas of wide open 

space. As a rule of thumb, a wind turbine requires 60 acres of land per megawatt. In the majority 

of cases, the presence of the turbine does not preclude using the land for other purposes, for 

example, agricultural activities. 

6.3.2 Planned or Existing Projects

Fort Carson explored an on-site wind project with GE, but determined that the energy price was 

too costly. Fort Carson personnel are currently pursuing an option to buy off-site wind power at 

$0.06-0.07/kWh through CSU from a wind farm in southern Colorado’s Baca County. 

6.3.3 Analysis

Fort Carson has a good wind resource in the southeast corner of the installation, about 20 miles 

south of the main base buildings. NREL measured the wind resource on site at Fort Carson from 

January 2008 to October 2009, using a 50m meteorological tower. In addition, we deployed a 

sonic detection and ranging (SODAR) unit between March and September 2008. Extrapolating 

from the measured data from the 50 meter tower, we estimate a resource of 6.8 m/s at 80 m. This 

estimate agrees with the NREL-validated wind map estimates of 6.5-7m/s at the meteorological 

tower site. Based on this resource, we estimate that a GE 1.5SLE turbine on an 80 meter tower 
48 

would produce 2,557,215 kWh per year (assuming losses of 11.5%). This equates to a with a 

19.5% capacity factor.

The map in Figure 22 shows the meteorological tower location (N38° 26.001, W 104° 44.372). 

The site will accommodate 6-8 wind turbines the size of a GE 1.5 SLE and has good access to 

Fort Carson’s 12/470 distribution line. The number of turbines is limited by available area on the 

ridgeline (where the best wind resource is) and Fort Carson munitions testing in the surrounding 

area. There is more land available in the area that may actually have a stronger wind resource 

than the measured meteorological site, but this land is privately owned. If this land should 

become available for development, a larger wind farm would be possible with access to 

transmission lines on the private property. Such a project, because of its larger size, would have 

better economics. 

Figure 22. Wind resources in the Fort Carson area (Credit: Owen Roberts, NREL)

Meteorological Tower
49 

6.3.4 Economic Analysis

Table 14 shows an economic analysis of wind power at Fort Carson. 

Table 14. Economic Analysis of Wind Power

Wind Capacity (kW) 10,500 

Wind Initial Cost ($) 19,509,000 

Wind Federal Tax Credit ($) 5,852,700 

Wind Initial Cost with incentives ($) 13,656,300 

Wind Production Incentive ($/year) 17,967 

Wind Annual Energy Delivery (kWh/year) 17,967,104

Capacity Factor (%) 19.5%

Wind Annual Cost Savings ($) 916,740 

Wind Annual O&M Cost ($/year) 216,000

Wind Payback Period (years) 19

6.3.5 Recommendations 

Of all potential electricity-producing renewables at Fort Carson, wind has the shortest payback 

period. Despite this, the cost still remains higher than the current price of fossil fuel-generated 

electricity. GE evaluated a wind farm at Fort Carson, and estimated the electricity would cost 

$0.10/kWh. In the future, as electricity prices increase, the on-site project may make better 

economic sense. Another option would be to bundle the on-site project with a lower-cost off-site 

project like Baca County. Under this scenario, the overall price might be $0.07/kWh. 

6.4 Photovoltaic (PV) Power 

6.4.1 Technology Overview

PV panels convert sunlight directly into electricity. They have no moving parts, require very 

little maintenance, make no noise, and emit no pollution. They are highly reliable and last 25 

years or longer. They may be installed on racks on the ground, mounted on poles, or mounted on 

rooftops or carports. 

6.4.2 Planned or Existing Projects

Fort Carson has the Army’s largest solar array, a 2 MW ground-mounted system completed in 

January 2008 (see Figure 23). In 2009 the base had the opportunity to build a second 1.3 MW 

array near the housing, but delays in the land lease caused the developer to move on to another 

project. 
50 

Figure 23. Fort Carson 2-MW solar array (Credit: U.S. Army Fort Carson, PIX 17394) 

6.4.3 Analysis

Fort Carson has ample rooftop, parking, and ground space for additional PV arrays. NREL 

analyzed satellite images of parking lot and rooftop space in the proposed microgrid area and 

identified locations for 10.74 MW of PV. Figure 24 shows the locations identified. Note that it 

would be necessary to build carports in the parking lots to accommodate PV. 
51 

Figure 24. Potential rooftop (blue) and carport (purple) locations in the microgrid area

Based on building square footages and an estimated average rooftop space availability factor of 

25%, we estimate that there is room for an additional 23 MW of rooftop PV on the rest of the 

base. Parking areas on the rest of the base could hold over 100 MW of PV. In addition to rooftop 

and carport locations, Fort Carson master planners have identified potential locations for 18 MW 

of ground-mounted PV projects. These include areas north and south of the existing array, 

pockets around the airfield (where height restrictions prevent the land being used for other 

purposes), and a large area on the northeast side of the base, west of I-25. 

Table 15 summarizes total potential PV capacity at Fort Carson. In total, we estimate that the 

base could mount 165.8 MW of PV on rooftops, carports, and ground areas around the 

installation. 
52 

Table 15. Potential PV Capacity at Fort Carson

Site

Approximate 

Area

Estimated 

Space for 

PV

Estimated 

PV Array 

Size

Estimated 

AC Energy

(ft2) (%) (kW) (kWh/year)

Ground mount PV - 20° tilt fixed

Signal Hill 310,000 100% 1,200 1,750,732

Airfield Area 1 480,000 100% 2,000 2,917,886

Airfield Area 2 480,000 100% 2,000 2,917,886

Airfield Area 3 480,000 100% 2,000 2,917,886

Former landfill south 

of existing array 260,000 100% 1,000 1,458,943

NE corner of base near 

I-25 2,600,000 100% 10,000 14,589,430

Total 18,200 26,552,763

Rooftop PV - 39° tilt fixed

Bld 1014 3,250 100% 33 49,368

Bld 1118 11,723 100% 117 178,072

Bld 1430 10,329 100% 103 156,898

Bld 1435 0 100% 0 0

Bld 1444 2,400 100% 24 36,456

Bld 1525 52,700 100% 527 800,513

Bld 1526 4,807 100% 48 73,018

Bld 1550 25,330 100% 253 384,763

Bld 1551 1,416 100% 14 21,509

Bld 1805 4,221 100% 42 64,117

Bld 1829 17,930 100% 179 272,357

Bld 1860 2,554 100% 26 38,795

Other Buildings 

outside microgrid area 9,145,340 25% 22,863 34,729,429

Total 24,230 36,805,294

Carport PV- 0° tilt fixed

Carport for Bld 1525 155,383 80% 1,243 1,538,915

Carport for Bld 6110 222,441 80% 1,780 2,203,052

Carport for Bld 1610 68,638 80% 549 679,790

Carport for Bld 1511A 30,635 80% 245 303,404

Carport for Bld 1511B 32,193 80% 258 318,839

Carport for Bld 1532A 55,281 80% 442 547,498

Carport for Bld 1532B 40,455 80% 324 400,665

Carport for Bld 1526A 34,083 80% 273 337,559

Carport for Bld. 1526B 18,533 80% 148 183,554

Carport for Bld. 1829A 58,679 80% 469 581,159
53 

Carport for Bld. 1829B 38,509 80% 308 381,396

carport for Bld. 1550A 6,977 80% 56 69,096

Carport for Bld. 1550B 14,185 80% 113 140,490

Carport for Bld 1550 C 22,136 80% 177 219,232

Carport for Bld. 1551 11,144 80% 89 110,375

Carport for Bld. 1552A 31,323 80% 251 310,221

Carport for Bld. 1552B 41,105 80% 329 407,107

Carport for Bld 1554A 38,519 80% 308 381,490

Carport for Bld 1554B 27,106 80% 217 268,457

Carport for Bld 1013 96,344 80% 771 954,192

Carport for Bld. 1118 70,253 80% 562 695,789

Carport for Bld 1444A 21,863 80% 175 216,531

Carport for Bld 1444B 36,282 80% 290 359,336

Other carports outside 

microgrid area 14,250,000 80% 114,000 141,132,000

Total 123,377 152,740,150

Ground Mount, Rooftop, & Carport PV Total

Total 165,806 216,098,207

Table 16 shows the assumptions we used for energy output, energy density, and cost for each 

system type.

Table 16. PV Systems Energy and Cost Assumptions

System Type

Annual energy 

(kWh/kW)

Installed Cost

($/W)

Energy Density

(W/ft2)

Roof Top Mount 39 Degree 

Tilt 1,519 $6.00 10 

Ground Mount 20 Degree 

Fixed Tilt 1,459 $5.00 3.8

Carport, 0 Degree Tilt 1,238 $7.50 10

6.4.4 Economic Analysis

NREL carried out an economic analysis for 1 MW ground mount, rooftop, and carport systems.

Assuming a 30% Federal tax credit and REC sale at $0.05/kWh, paybacks vary from 26-46 

years, as Table 17 shows. 
54 

Table 17. PV Economic Analysis

Ground Mount

PV Capacity (kW) 1,000

Initial Cost ($) 5,000,000

REC Sale ($/yr) 72,950

Federal Tax Credit ($) 1,500,000

Annual Energy Delivery (kWh/yr) 1,459,000

Annual Utility Cost Savings ($) 72,950

Annual O&M Cost ($/yr) 9,932

Payback Period (yrs) 26

Rooftop

PV Capacity (kW) 1,000

Initial Cost ($) 6,000,000

REC Sale ($/yr) 75,950

Federal Tax Credit ($) 1,800,000

Annual Energy Delivery (kWh/yr) 1,519,000

Annual Utility Cost Savings ($) 75,950

Annual O&M Cost ($/yr) 9,932

Payback Period (yrs) 30

Carport

PV Capacity (kW) 1,000

Initial Cost ($) 7,500,000

REC Sale ($/yr) 61,900

Federal Tax Credit ($) 2,250,000

Annual Energy Delivery (kWh/yr) 1,238,000

Annual Utility Cost Savings ($) 61,900

Annual O&M Cost ($/yr) 9,932

Payback Period (yrs) 46

6.4.5 Recommendations 

Fort Carson has a number of potential sites for PV installation on ground areas, rooftops, and 

carports. Ground mount systems have the best payback period and Fort Carson has past 

experience funding large ground mount systems through power purchase agreements (PPAs). 

Therefore we recommend pursuing these opportunities first. Fort Carson may also be able to 

fund individual rooftop systems through Army Corps of Engineer building funds. 

6.5 Solar Hot Water

6.5.1 Technology Overview

Solar water heating systems consist of solar collectors to capture the sun’s heat and tanks to store 

the hot water for later use. Operation is similar to a hydronic heating system, with the solar 

collectors as heat sources, heat exchangers to heat potable water, pumps to circulate the fluid, 

expansion tanks, pressure relief valves, flush and fill valves, and controls. There are three types 
55 

of solar water heating collectors: 1) unglazed plastic collectors for low temperatures such as 

swimming pool heating; 2) glazed, insulated flat plate collectors for mid-temperature service hot 

water; and 3) evacuated tube collectors with reflectors for high temperature applications. Typical 

solar water heating systems provide 40-70% of water-heating requirements. They are often

installed on rooftops. 

6.5.2 Existing or Planned Projects

Fort Carson has a solar hot water heating system installed at its indoor pool, as Figure 25 shows. 

Figure 25. Solar hot water at Fort Carson indoor pool (Credit: John Leahey, NREL) 

6.5.3 Analysis

Table 18 identifies opportunities for solar water heating. We selected these buildings based on 

building type, but further analysis of building orientation, roof type, and roof space is still 

needed. 
56 

Table 18. Potential Candidates for Solar Hot Water System

Building 

Number Name

Building 

Type

Building 

Size (ft

2

)

Estimated 

Hot Water 

Load (KBtu)

% 

Served 

by Solar 

Thermal

MMBtu 

reduction

1040 Cheyenne Dining Facility Dining 13,280 87,714 60% 53

1369

Mountaineer Dining 

Facility Dining 13,280 87,714 60% 53

2161 Patton Dining Facility Dining 18,222 120,355 60% 72

2061 Striker Dining Facility Dining 18,222 120,355 60% 72

2461 Warhorse Dining Facility Dining 16,724 110,461 60% 66

1444 Wolf Dining Facility Dining 28,621 189,040 60% 113

1856 Garcia Gym Gym 23,159 25,485 60% 15

1843 Forrest Gym Gym 17,502 19,259 60% 12

1160 McKibben Gym Gym 20,375 22,421 60% 13

2357 Waller Gym Gym 24,895 27,395 60% 16

1661 WCAP Fitness Center Gym 13,280 14,614 60% 9

1219 ARMY LODGING Lodging 18,012 304,678 60% 183

7302 ARMY LODGING Lodging 36,027 609,406 60% 366

7303 ARMY LODGING Lodging 12,746 215,602 60% 129

7304 ARMY LODGING Lodging 36,027 609,406 60% 366

7305 ARMY LODGING Lodging 12,330 208,565 60% 125

7500 MED CTR/HOSP Clinic 513,700 14,499,785 60% 8,700

1041 HEALTH CLINIC Clinic 11,321 319,549 60% 192

2353 HEALTH CLINIC Clinic 10,080 284,520 60% 171

7490 HEALTH CLINIC Clinic 15,110 426,497 60% 256

756 ENLISTED UPH Barracks 95,858 1,621,462 60% 973

758 ENLISTED UPH Barracks 95,858 1,621,462 60% 973

1000 ENLISTED UPH Barracks 63797 1,079,142 60% 647

1013 ENLISTED UPH Barracks 23,246 393,212 60% 236

1043 ENLISTED UPH Barracks 40,639 687,419 60% 412

1044 ENLISTED UPH Barracks 40,639 687,419 60% 412

1046 ENLISTED UPH Barracks 40,639 687,419 60% 412

1047 ENLISTED UPH Barracks 40,639 687,419 60% 412

1219 ENLISTED UPH Barracks 14,549 246,100 60% 148

1363 ENLISTED UPH Barracks 40,639 687,419 60% 412

1364 ENLISTED UPH Barracks 40,639 687,419 60% 412

1365 ENLISTED UPH Barracks 40,639 687,419 60% 412
57 

1366 ENLISTED UPH Barracks 40,639 687,419 60% 412

1367 ENLISTED UPH Barracks 40,639 687,419 60% 412

1449 ENLISTED UPH Barracks 93,297 1,578,142 60% 947

1552 ENLISTED UPH Barracks 123,860 2,095,123 60% 1,257 

1554 ENLISTED UPH Barracks 123,860 2,095,123 60% 1,257

1663 ENLISTED UPH Barracks 40,639 687,419 60% 412

1664 ENLISTED UPH Barracks 40,639 687,419 60% 412

1665 ENLISTED UPH Barracks 40,639 687,419 60% 412

1666 ENLISTED UPH Barracks 40,639 687,419 60% 412

1667 ENLISTED UPH Barracks 40,639 687,419 60% 412

1950 ENLISTED UPH Barracks 11,819 199,921 60% 120

1951 ENLISTED UPH Barracks 22,386 378,665 60% 227

1952 ENLISTED UPH Barracks 22,386 378,665 60% 227

1953 ENLISTED UPH Barracks 22,386 378,665 60% 227

1954 ENLISTED UPH Barracks 22,386 378,665 60% 227

2050 ENLISTED UPH Barracks 22,386 378,665 60% 227 

2051 ENLISTED UPH Barracks 22,386 378,665 60% 227

2052 ENLISTED UPH Barracks 22,386 378,665 60% 227

2053 ENLISTED UPH Barracks 11,819 199,921 60% 120

2054 ENLISTED UPH Barracks 22,386 378,665 60% 227

2070 ENLISTED UPH Barracks 11,819 199,921 60% 120

2071 ENLISTED UPH Barracks 22,386 378,665 60% 227

2072 ENLISTED UPH Barracks 22,386 378,665 60% 227

2073 ENLISTED UPH Barracks 22,386 378,665 60% 227

2074 ENLISTED UPH Barracks 22,386 378,665 60% 227

2144 ENLISTED UPH Barracks 152,684 2,582,689 60% 1,550

2146 ENLISTED UPH Barracks 152,684 2,582,689 60% 1,550

2150 ENLISTED UPH Barracks 22,386 378,665 60% 227 

2151 ENLISTED UPH Barracks 22,386 378,665 60% 227

2152 ENLISTED UPH Barracks 22,386 378,665 60% 227

2153 ENLISTED UPH Barracks 11,819 199,921 60% 120

2154 ENLISTED UPH Barracks 22,386 378,665 60% 227

2250 ENLISTED UPH Barracks 11,819 199,921 60% 120

2251 ENLISTED UPH Barracks 22,386 378,665 60% 227

2252 ENLISTED UPH Barracks 22,386 378,665 60% 227

2253 ENLISTED UPH Barracks 22,386 378,665 60% 227

2254 ENLISTED UPH Barracks 22,386 378,665 60% 227
58 

2340 ENLISTED UPH Barracks 152,684 2,582,689 60% 1,550

2344 ENLISTED UPH Barracks 152,684 2,582,689 60% 1,550

2346 ENLISTED UPH Barracks 152,684 2,582,689 60% 1,550

2450 ENLISTED UPH Barracks 22,441 379,595 60% 228 

2451 ENLISTED UPH Barracks 22,441 379,595 60% 228

2452 ENLISTED UPH Barracks 22,441 379,595 60% 228

2453 ENLISTED UPH Barracks 22,441 379,595 60% 228

2454 ENLISTED UPH Barracks 22,441 379,595 60% 228

2550 ENLISTED UPH Barracks 22,441 379,595 60% 228

2551 ENLISTED UPH Barracks 22,441 379,595 60% 228

2552 ENLISTED UPH Barracks 22,441 379,595 60% 228

2554 ENLISTED UPH Barracks 22,441 379,595 60% 228

7480 ENLISTED UPH Barracks 60,217 1,018,586 60% 611

7482 ENLISTED UPH Barracks 60,217 1,018,586 60% 611

7506 ENLISTED UPH Barracks 49,560 838,320 60% 503

9471 MOB ENL BRKS Barracks 30,410 514,393 60% 309 

9472 MOB ENL BRKS Barracks 30,410 514,393 60% 309

9473 MOB ENL BRKS Barracks 30,410 514,393 60% 309

9474 MOB ENL BRKS Barracks 30,410 514,393 60% 309

811 TT ENL BARRACKS Barracks 35,560 601,506 60% 361

812 TT ENL BARRACKS Barracks 31,305 529,532 60% 318

Total 41,774

For the net zero analysis, we assume that half of these installations will be viable, resulting in a 

total of 43,441 square feet of solar hot water area and 20,887 MMBtu of annual energy savings. 

6.5.4 Economic Analysis

Table 19 shows estimated costs, savings, and payback for installing solar hot water systems on 

the buildings identified in Table 18. 

Table 19. Solar Hot Water Financial Estimate

Solar Water Heating Area (ft

2

) 43,441

Solar Water Heating Initial Cost ($) $3,026,786

Rebates and Incentives ($) 0

Solar Water Heating Gas Savings (MMBtu/yr) 20,887

Solar Water Heating Annual Utility Cost Savings ($/yr) $115,603

Solar Water Heating O&M Cost ($/yr) $15,134

Solar Water Heating Payback Period (yrs) 30.1
59 

6.5.5 Recommendations 

Our assessment indicates that solar hot water systems would not be cost-effective at Fort Carson

at this time. With a lifetime of 15-30 years, the system is likely to fail before the initial 

investment has been repaid. It may be possible to reduce the payback period by implementing 

systems through a private party―such as energy savings performance contracts (ESPC) or utility 

energy services contracts (UESC)―which can take advantage of Federal tax incentives. Systems 

may also become more cost-effective as fossil energy prices increase, as many observers predict.

If Fort Carson does pursue solar hot water systems, we recommend giving priority to dining 

facilities, gyms, barracks, and the new pool. 

6.6 Biomass

6.6.1 Technology Overview

Several technologies are available to convert biomass feedstocks into heat and electricity. In this 

analysis, we evaluate combustion, the direct burning of a feedstock such as wood waste with air 

to produce steam, which can then be used to create both heat and power. This is typically the 

most economical method of converting biomass fuel to heat and power.

6.6.2 Planned or Existing Projects

Fort Carson has received two unsolicited proposals for biomass systems: 

1. The first proposal is for a combined heat and power (CHP) direct combustion system. 

NREL conducted a detailed study of a CHP plant capable of providing 5 MW of 

thermal power and 7 MW of electrical power. These levels were selected based on 

Fort Carson’s seasonal heat load and a desire to maximize electricity production.

2. The second proposal is for a heat-only system. Under an energy purchase agreement, 

a wood-fired combustion boiler would supply hot water (30 MMBtu/hr) to the 

existing central distribution system at an estimated $15-20/MMBtu. 

Each of these options is evaluated below. 

6.6.3 Analysis

The National Energy Technology Laboratory (NETL)’s biomass resource database indicates 

there is 187,275 tons of woody biomass within a 50 mile radius of the base; Fort Carson

personnel estimate that an additional 10,000 tons of woody biomass exists on site (see Table 20).

Table 20. Biomass and Alternative Methane Fuel Resources near Fort Carson, CO

Radius

Number of 

Sources

Total Resource 

(Green 

Tons/Year)

Estimated 

Energy 

(MMBtu)

Estimated 

Power 

(MWe)

Industrial Wood Residue 50 34 48,620 131,274 4.39

Western Forest Fire 

Mitigation Residue 50 5 138,655 374,367 12.52

Fort Carson 0 1 10,000 27,000 0.90

TOTAL 197,275 532,641 17.81
60 

This is a sufficient supply of biomass fuel to supply either of the proposed systems; however, 

there are other, competing users of biomass. The primary challenge to fuel procurement will be 

competition from the nearby Colorado Springs Utilities’ biomass co-firing project at its Drake 

plant, which is expected to consume 100,000 tons of woody biomass fuel per year. This project 

will certainly pressure the existing supplier base while promoting the development of additional 

biomass fuel procurement, processing, and delivery options. 

6.6.4 Economic Analysis

Combined Heat and Power System

NREL conducted a detailed feasibility analysis of a CHP system that would supply 5 MW of 

thermal power and 7 MW of electrical power to the post. The study found local market 

conditions for biomass fuel are unfavorable for the development of a biomass-fired heat and 

power system. The originally proposed system was based on a delivered price for biomass fuel of 

$30 per ton. Actual market research found only one vendor capable of providing fuel near this 

price point. However, the quality of their fuel was not adequate for a Fort Carson project. 

The actual delivered price to ship biomass of adequate quality from off post was found to be 

$50-$60 per ton. This is the price currently paid by Colorado Springs Utilities at the Drake 

biomass plant, and is significantly above the national average, primarily due to lengthy transport 

required from forestry biomass sources in the region. Assuming 25% moisture content and 8,000 

Btu per bone-dry pound, the adjusted cost for the heating value of the fuel is $4.58/MMBtu. 

Current estimates indicate 10,000 tons of woody biomass may be procured from sources on Fort 

Carson property each year. We estimate that the delivered cost for this material would be $20 per 

ton. Adjusting for moisture, the cost for the heating value of this fuel is approximately 

$1.79/MMBtu. This resource is much more economical but would reduce or eliminate a popular 

firewood program on post. Fort Carson’s firewood program provides soldiers and their families 

with low-cost firewood, and discontinuing the program is undesirable. 

The biomass CHP plant (supplying 5 MW thermal power and 7 MW of electrical power) would 

require approximately 100,000 tons of biomass fuel per year to operate. If 10,000 tons were 

procured on post, with 90,000 tons imported from other locations, the blended rate for heat is 

$4.30/MMBtu. The cost of producing electricity from biomass is much higher due to the low 

efficiency of converting the heat to electricity. Assuming 20% conversion efficiency, the blended 

rate for electricity is about $21.50/MMBtu. O&M costs will add approximately $5-6/MMBtu, 

resulting in a rate closer to $27/MMBtu. For comparison, Fort Carson’s 2009 costs were

$5.44/MMBtu for heat input into its system and $14.65/MMBtu for electricity. 

Using 2009 natural gas and electric rates and the above assumptions for biomass fuel costs, a 

biomass CHP plant would provide annual utility heating and electricity savings of $1.456 

million. The additional operating expense however, primarily due to the expense of biomass fuel, 

is $13.1 million. This huge operating expense makes a CHP project economically unviable at this 

time. Table 21 outlines the economics for this scenario. 
61 

Table 21. Economic Analysis of Biomass CHP

2009 Delivered Cost of Natural Gas $5.44

Blended Delivered Cost for Biomass Heat $4.30

Annual Heat Produced (MMBtu) 200,000

Annual Heat Savings ($/year) $228,000

2009 Cost of Electricity ($/kWh) $0.05

Annual Electricity Production (kWh) 24,552,000

Annual Electricity Savings ($) $1,227,600 

Total Annual Utility Savings $1,455,600

Annual O&M ($/year) $13,117,000

Capital Cost for New Plant $61,300,000

Simple Payback (years) Negative

Sensitivity analysis indicates that an increase in the utility electricity rate to approximately 

$0.26/kWh would result in a positive net present value for the project. A rate of about 

$0.30/kWh would provide a 12% rate of return, and make the project attractive to a potential 

developer. 

Heat-Only System

The proposed 30 MMBtu/hr biomass heating project would require approximately 16,000 tons of 

biomass per year to operate. The majority of this amount (10,000 tons) may be procured on site, 

with the remaining 6,000 tons imported. Using the respective costs for these sources of $1.79 and 

$4.58, the blended rate is $2.84/MMBtu. Again using $5.44/MMBtu as the natural gas cost

benchmark, and presuming a 30 MMBtu/hr project can meet 80% of Fort Carson’s heating 

demand (peak times will require an additional boiler), there is a potential savings of $416,000 

per year in heating costs. Based on estimated capital and O&M costs, the payback for this project 

is 29.3 years. 
62 

Table 22. Economic Analysis of Biomass Heat Only

2009 Delivered Cost of Natural Gas $5.44 

Blended Delivered Cost for Biomass Heat $2.84 

Annual Heat Produced (MMBtu) 160,000

Annual Heat Savings ($/year) $416,000 

Additional O&M ($/year) $75,000 

Capital Cost for New Plant $10,000,000 

Simple Payback (years) 29.3

6.6.5 Permitting and Site Selection

The current heating plant is located in a congested area with little room for expansion. There is a 

site approximately 200 yards northeast of the current facility, at the perimeter of the currently 

developed area. This site would provide room for necessary fuel storage, would reduce the 

plant’s impact on nearby operations and residents, and would facilitate fuel deliveries. We 

recommend meeting with Fort Carson’s Master Planner to determine the viability of this 

location. The new facility would be tied into the current heating distribution point by running 

lines to the current heating building and connecting there. The existing facility will remain in 

place and operable, serving as an installed backup for the sake of redundancy. 

Supplying thousands of tons of material each year could be potentially disruptive to base 

operations. We recommend delivery trucks enter Gate 3, use O’Connell Boulevard, and keep 

close to the base perimeter on MacGrath Avenue to minimize disturbance.

In addition to master planner approval, the facility would require significant permitting

including: 

• Air Permit. May require Title V and Potential for Significant Deterioration (PSD) 

permitting, pending results from the EPA’s review of its Tailoring Rule. 

• New Source Review. Fort Carson is in a maintenance zone for carbon monoxide and a 

non-attainment zone for ozone. 

• NEPA Study. A National Environmental Policy Act (NEPA) study shows that there is

potential concern for impact on endangered wildlife and on troop training areas. 

Initial, Final, and Title V permits will be secured by the contractor and are expected to take 24-

30 months to attain after the project is awarded.

6.6.6 Recommendations 

NREL’s analysis determined a biomass CHP plant is not viable. A small heating-only plant may 

still be viable. We recommend continued review of this option, including the collection of 

detailed cost estimates and further discussion with the post’s firewood program managers to 

determine the impact of using this resource. Also, continued monitoring of the local biomass 

market will help determine if the Colorado Springs Utilities project promotes the development of 

local resources and allows lower-cost biomass fuel to be procured. 
63 

6.7 Other Combined Heat and Power Options

Because a biomass-fueled combined heat and power plant is economically unviable at this time, 

other cogeneration options that use non-renewable fuels were evaluated. While these options 

would still require the use of natural gas, they would provide a reduction in source energy, 

because electricity generated on site suffers fewer transmission losses than electricity that is 

generated off site and transported through the transmission grid. The non-renewable

cogeneration option would also reduce the installation’s overall carbon footprint, since electrical 

energy generated with natural gas has a lower carbon fuel requirement than the average 

generation mix of CSU. In addition, the waste heat from the generation process would be utilized 

on base. If Fort Carson pursues these options, we recommend the evaluation of renewable natural 

gas supplies as well. Using renewable natural gas to power cogeneration units would increase net 

zero energy potential and further reduce the base’s carbon footprint. In the sections immediately 

following, we discuss three cogeneration options: natural gas cogeneration, microturbines, and 

fuel cells. 

Natural Gas Cogeneration

Natural gas cogeneration units typically serve large-scale residential, commercial, or industrial 

applications. System sizes typically are 500 kW or greater. The most common technologies used

for a cogeneration system is a natural gas powered turbine or internal combustion engine. 

A natural gas cogeneration system, which produces electricity, hot water, and chilled water, was 

evaluated for the NREL campus in Golden, CO, where heat and electricity rates are similar to 

Fort Carson’s12. Results show a 4.2 MW Wartsilla internal combustion engine would reduce 

greenhouse gases by 39% with a simple payback of 8.47 years. A 4.6 MW Mercury 50 gas 

turbine would reduce greenhouse gases by 36% with a payback of 14.52 years. Fort Carson 

would likely use a larger system closer to its average load of 20 MW. For systems over 10 MW, 

the electrical efficiencies of gas turbines increase substantially, and payback for a 20 MW system 

at Fort Carson could be less than 10 years. 

Microturbines

6.7.1 Technology Overview

Microturbines are small combustion turbines with outputs between 5 kW and 500 kW (see photo 

in Figure 26). They are best suited to supply the load of individual buildings at Fort Carson that 

are not served by the central heating plant. These small systems are most economical when the 

user is able to take advantage of both the thermal and electrical energy that the system produces.

Microturbines can be coupled with existing building energy systems and should be sized so that 

the heat output of the turbine is less than the building’s load. The heat from the microturbine can 

also be used in conjunction with an adsorption chiller to cool a building. The best candidates for 

this type of equipment are buildings that are not on centralized systems and have natural gas 

loads above 1,500 MMBtu annually. Electrical efficiency is typically between 15% and 40%; 

thermal use can make the total efficiency as high as about 90%. 

 

12 Dean, Jesse. “Design of a Hybrid Distributed Generation System for NREL’s South Table Mountain Campus.” 

University of Colorado, Boulder. April 29,2010. 
64 

Figure 26. 30 kW Capstone Microturbines (Credit: Capstone Turbine Corporation, PIX 08130)

6.7.2 Economic Analysis

NREL carried out an economic analysis of microturbines for Fort Carson (see Table 23). We 

found that microturbines are not cost-effective at this time, because the price of electricity is low 

compared to the price of natural gas. The cost of a Btu of electricity needs to be approximately 

four times the cost of a Btu of natural gas in order to justify the capital cost for a microturbine 

installation. At Fort Carson’s 2009 natural gas price of $5.44/MMBtu, the price of electricity

would need to rise from the current $0.050/kWh to at least $0.075/kWh to make microturbines 

life-cycle cost effective within a 25 year period. At the current natural gas rate of $6.26/MMBtu, 

the price of electricity would need to rise to at least $0.081/kWh.
65 

Table 23. Microturbine Analysis

Base Case Natural Gas Heating

Natural Gas Load (MMBtu) 2,000 

Estimated Boiler Efficiency 80%

Heating MMBtu Required 1,600

Natural Gas Cost ($/MMBtu) 5.44

Total Natural Gas Cost $10,880 

Microturbine CHP

Microturbine Electrical Efficiency 25%

Microturbine Thermal Efficiency 35%

Total Efficiency 60%

Natural Gas Load (MMBtu) 4,571

Heating MMBtu Required 1,600

MMBtu Converted to Electric 1,143

kWh Produced 334,854

Natural Gas Cost ($/MMBtu) $5.44 

Total Natural Gas Cost $24,866 

Value of Electrical Energy (per 

kWh) $0.05 

Total Electrical Energy Value $16,743 

System Size Required (kW) 38

Installed System Size (kW) 60

Installed Cost ($/kW) $2,175 

Total Cost $130,500 

Annual Maintenance ($/kWh) $0.01 

Annual Maintenance Cost $3,516 

Annual Saving ($760)

Simple Payback (yrs) Negative

6.7.3 Recommendations 

While not cost-effective now, CSU is predicting that electric rates will rise sharply in coming 

years. Therefore, microturbines may become cost-effective in the future for buildings that are not 

on the central heat distribution system. Additionally, when replacing old boilers at Fort Carson, 

the base should compare the capital cost of a new boiler with a microturbine system, as this 

scenario would likely provide more favorable economic conditions for the installation of a 

microturbine. Microturbines would strengthen a microgrid at Fort Carson and provide backup 

power in an islanded scenario. 
66 

Fuel Cells

6.7.4 Technology Overview

Fuel cells offer another option for CHP at Fort Carson. Fuel cells have high efficiency and low 

emissions in comparison with other conventional cogeneration systems. There are several 

different types of fuel cells, such as phosphoric acid, proton exchange membrane (PEM), solid 

oxide, and molten carbonate. The fuel source for these cells is typically hydrogen or a methanebased fuel, such as natural gas or renewably derived biogas. Fuel cell systems are sized based 

primarily on the thermal load that can be displaced in a particular area. The electrical energy 

produced by the fuel cell would be put into the base distribution network and could be utilized 

anywhere on base; however, the thermal load must be used on site. Housing areas, with their

high space heating and domestic hot water needs, are prime candidates. 

During a grid outage, the fuel cell power plant disconnects from the utility grid in milliseconds 

and then continues to produce power to serve the customer’s critical loads. This “island” 

operation would strictly serve dedicated loads (as well as the loads of the fuel cell system itself), 

without allowing any power to be exported to an otherwise unpowered utility grid. After power 

returns to the utility grid and is stable, the fuel cell is designed to automatically synchronize its 

power to the grid, while providing continuous power to the critical loads. If critical backup is not 

required by the customer, then the fuel cell power system uses island mode to maintain power for 

its own process loads and remains ready for reconnection to the utility grid on return of live-grid 

power. 

6.7.5 Economic Analysis

NREL carried out an economic analysis of fuel cells for Fort Carson (see Table 24). This 

analysis looks at a 1400 kW cell with 40% electrical efficiency and 80% overall efficiency. The 

heat produced by this system would displace about 40,000 MMBtu annually, or about one-fifth 

the annual natural gas use of Fort Carson’s privatized housing. 
67 

Table 24. Area 5 Fuel Cell Analysis

Base Case Natural Gas Heating

Natural Gas Load (MMBtu) 40,000 

Estimated Boiler Efficiency 80%

Heating MMBtu Required 32,000 

Natural Gas Cost ($/MMBtu) 5.44

Total Natural Gas Cost $217,600 

Fuel Cell CHP

Fuel Cell Electrical Efficiency 40%

Fuel Cell Thermal Efficiency 40%

Total Efficiency 80% 

Natural Gas Load (MMBtu) 80,000 

Heating MMBtu Required 32,000 

MMBtu Converted to Electric 32,000 

kWh Produced 9,378,664 

Natural Gas Cost ($/MMBtu) $5.44 

Total Natural Gas Cost $435,200 

Value of Electrical Energy (per 

kWh) $0.05 

Total Electrical Energy Value $468,933 

Installed System Size (kW) 1,400

Installed Cost ($/kW) $4,500 

Total Cost $6,300,000 

Annual Maintenance ($/kWh) $0.01 

Annual Maintenance Cost $103,165 

Annual Saving $148,168 

Simple Payback (yrs) 43

Our analysis found that fuel cells are not cost-effective at this time, because of the low price of 

electricity compared to natural gas at Fort Carson. For fuel cells to be life-cycle cost effective 

over a 25 year period, Fort Carson’s electricity price would need to increase to $0.075/kWh 

(versus the current $0.05/kWh) compared to Fort Carson’s 2009 natural gas price of 

$5.44/MMBtu. 

6.7.6 Recommendations 

While not cost-effective now, CSU is predicting that electric rates will rise sharply in coming 

years, so fuel cells may become cost-effective in the future for buildings that are not on the 

central heat distribution system. Additionally, fuel cells are only in the early stages of 

commercialization, with many technologies still under development. Costs will likely decrease 
68 

as technologies improve. In an islanded scenario, fuel cells would strengthen a microgrid at Fort 

Carson and provide backup power. 

Overall CHP Recommendation

CHP provides a promising opportunity for Fort Carson to reduce costs, reduce emissions, and 

increase energy security at the base. Natural gas powered cogeneration appears to be the most 

economically viable technology, and we recommend evaluating opportunities to convert the 

central heat plant to a combined heat and power plant. In the future, if electric prices increase 

significantly compared to natural gas prices, we recommend considering microturbines or fuel 

cells. 

6.8 Concentrating Solar Power

6.8.1 Technology Overview

Electricity and steam can be produced through a solar thermal process using concentrating solar 

power (CSP). Collectors focus solar heat onto a fluid, the heat creates steam, which turns a 

turbine or engine attached to a generator to create electricity. Motors and controls track the sun. 

Although these systems include minimal moving parts, they do require preventative and 

unscheduled maintenance. Two concentrating solar power production technologies are dish 

Stirling engines and parabolic troughs. Commercial dish Stirling engines are usually about 1 

MW in size. Commercial parabolic troughs range from 50-200 MW, and require 5-10 acres of 

land per megawatt. Trough designs incorporating thermal energy storage can provide baseload 

power. 

6.8.2 Planned Project

Fort Carson is planning a CSP demonstration project. The base has submitted an Environmental 

Security Technology Certification Program (ESTCP) proposal to demonstrate an Infinia 3kWe

SolarDish, a dish Stirling engine that is integrated into a building system to provide 7 kWt for 

space heating and hot water, in addition to 3 kWe of electric power. The proposal will 

demonstrate one dish, but there is potential to scale the system to larger sizes by adding 

additional units. The small size makes it easier to site, because it does not require the large 

contiguous land areas required by conventional trough systems. The system is expected to 

generate 7,400 kWh AC electricity and 22,000 kWh of thermal energy annually. System cost 

information is not currently available. 

Fort Carson is also a part of the Front Range Renewable Energy Consortium (FRREC), which is 

considering a ~100 MW CSP parabolic trough project. The consortium is considering two tracts 

of land: 1) the Nixon power plant, adjacent to the southeast corner of Fort Carson; and 2) the 

Pueblo Chemical Depot. Although neither of these sites lie within the Fort Carson boundary, so 

would not meet the net zero definition of on-site renewable generation, either site could 

nonetheless provide a source of off-site renewable energy. 

6.8.3 Analysis

NREL used the Solar Advisory Model (SAM) to analyze the potential for a CSP trough project 

on site at Fort Carson. Potential sites include 1) land in the northeast corner of the installation 

between the main site and I-25, or 2) part of the land currently used for training on the south side 

of the installation. Use of either of these sites would require support from Fort Carson’s Master 
69 

Planners and the current users (range/training). Neither of these areas has been surveyed for 

suitability. A trough system will require relatively flat land. 

Fort Carson’s electrical demand averages about 21 MW throughout most of the year, rising to 25 

MW in the summer and dropping just below 20 MW in the fall. For this analysis, we evaluate the 

costs and energy savings associated with a 20 MW system. This is small compared to most 

commercial parabolic trough systems, and results in a higher cost of energy than would be 

attained with a larger system. However, larger tracts of land are not currently available at Fort 

Carson. We analyzed both north-south and east-west orientations, and recommended an eastwest orientation. The east-west system produces 6% less energy annually than a north-south 

system, resulting in a slightly higher levelized cost of energy (LCOE), but, importantly, it 

provides a more constant level of power. Between summer and winter, the daily energy output of 

the north-south systems varied by a multiple of two to three times. 

Parabolic trough plants can incorporate thermal energy storage (TES) by storing the heat transfer 

fluid or a dedicated thermal storage fluid at high temperature for later use. This analysis 

evaluated storage options from 0-18 hours. We selected the field and TES size to minimize 

LCOE and avoid energy dumping. Storage was capped at 18 hours full-load capacity to avoid 

excessive pumping losses for the large solar field.

This analysis assumes all energy generated will be used to produce electricity. It may also be 

possible, however, to use the steam directly for heating by connecting the CSP system to the 

centralized steam distribution network on the north end of the installation. Cost and feasibility 

would depend on the site of the CSP plant and its proximity to existing steam lines. 

6.8.4 Economic Analysis

Table 25 outlines the economics of a 20 MW system with six hours of thermal storage. We 

calculated a simple payback period, assuming that the project is implemented through a private 

party to take advantage of Federal tax credits, and the RECs are sold. 
70 

Table 25. CSP Energy Generation and Costs

Solar Field Size (m2) 278,182

Plant Footprint (acres) 54

Thermal Storage (hours) 6

Annual Power Generation 

(MWh) 50,000 

Percent of Fort Carson Annual 

Energy Use (%) 31% 

LCOE ($/kWh) 19.86

Installed Cost ($) 184,000,000 

Federal Tax Credit ($) 55,200,000

REC Sale ($/yr) 2,500,000 

Annual O&M Cost ($/yr) 1,750,000

Annual Utility Savings ($/yr) 2,500,000 

Simple Payback Period (yr) 40

6.8.5 Recommendations 

The NREL analysis shows that CSP has potential for being an effective resource at Fort Carson. 

The ability to store energy makes CSP a good option for baseload renewable energy at the 

installation, where energy dependability is of great importance. The analysis shows that the lifecycle cost of energy is $0.1986/kWh for a 20 MW system with six hours of thermal storage. It 

would be possible to add more thermal storage without much effect on the life-cycle cost of 

energy, but this would require a larger solar collector and therefore more land. Because the 

ability to produce at constant level is important for the base, an east-west oriented collector field 

makes the most sense for Fort Carson. 

CSP systems of the size considered here are not cost-competitive with current fossil energy 

prices. If CSP costs decrease, or if fossil energy prices significantly increase, we would 

recommend reevaluating a CSP project. Until then, we recommend pursuing the joint FRREC 

CSP project, which will be more cost competitive because of its larger size. 

6.9 Ground Source Heat Pumps

6.9.1 Technology Overview

Ground source heat pumps (GSHPs) are used for space heating, space cooling and water heating.

GSHPs use the earth as a heat source/sink, operating through a series of pipes buried in the 

ground. A pump circulates a fluid through the pipes (water, or a mixture of water and antifreeze) 

that absorbs heat from, or relinquishes heat to, the surrounding soil, depending on whether the 

ambient air is colder or warmer than the soil. The technology relies on the fact that the earth 

(beneath the surface) remains at a relatively constant temperature throughout the year, warmer 

than the air above it during the winter and cooler in the summer. The geothermal heat pump 

takes advantage of this geological fact by transferring heat stored in the earth or in ground water 
71 

into a building during the winter, and transferring it out of the building and back into the ground 

during the summer. 

GSHPs can serve almost any building with both heating and cooling in a wide range of building 

sizes, from 100 to 1 million square feet. Large buildings may require multiple GSHPs. The same 

ground loop may serve multiple smaller buildings. GSHPs are most cost-effective when 

replacing old equipment, when used in extreme climates (with cold winters, hot summers, or 

large daily temperature swings), and when electricity is less than three times as expensive per 

Btu as heating fuels. They tend not to be cost effective in buildings without both heating and 

cooling requirements, buildings without ductwork, newer buildings (less than four years old), 

buildings in mild climates, buildings with air source heat pumps, or buildings on central energy 

plants. 

6.9.2 Existing or Planned Projects 

Fort Carson has recently installed several GSHP in new construction at the Band Training 

Facility, Soldier Family Assistance Center, and at a school. The installation plans a fourth system 

for a new child development center. 

6.9.3 Analysis

NREL conducted a high level analysis of potential ground source heat pump savings across the 

installation (see Table 26). 
72 

Table 26. Potential Energy Savings from Ground Source Heat Pumps

Current cost of heating and cooling individual buildings

2009 natural gas use (MMBtu) 921,407

Percent of natural gas that goes to individual buildings 

(not central heat plant) (%)

80%

Percent of natural gas used for space heating & cooling 

(versus water heating and cooking) (%) 

70%

Natural gas used for space heating and cooling (MMBtu) 515,988

Natural gas rate ($/MMBtu) $5.44

Current heating and cooling cost 2,806,976

GSHP cost of heating and cooling

Natural gas used for space heating and cooling (MMBtu) 515,988

Average boiler efficiency (%) 80%

Energy needed for space heating and cooling (MMBtu) 412,791

Average GSHP coefficient of performance 3

Electricity needed for GSHP (MMBtu) 137,597

Electric Rate ($/MMBtu) $14.65

GSHP heating and cooling cost ($) $2,016,366

Savings

Annual Energy Savings (MMBtu) 378,391

Annual Cost Savings ($) $790,609

GSHP Size

Buildings with individual heating systems (ft2) 12,100,000

GSHP Size (tons/ft2) 0.0015

Total GSHP needed (tons) 18,150

Economics

GSHP cost ($/ton) $2,500

Initial Cost ($) $45,375,000

Annual Savings ($/year) $790,609

Simple Payback period (years) 57

This analysis shows that GSHP are generally not cost-effective for retrofits. 

Pacific Northwest National Laboratory (PNNL) also conducted an analysis of GSHPs at Fort 

Carson in 2008.13 That analysis considered differences in building types and heating system 

 

13 Chvala, W.D.; Solana, A.E.; Sates, J.C.; Warwick, W.M.; Weimar, M.R., Reilly, R.W., and Dixon, D.R. 

Renewable Energy Opportunities at Fort Carson, Colorado. PNNL-18132. Pacific Northwest National Laboratory. 

December 2008.
73 

types. PNNL found that open loop configurations were economic for 992,000 square feet of 

building space (9% of buildings). In general, buildings with chillers and boilers with air handling 

units were most cost-effective, while buildings with air source heat pumps and fan coils were 

never cost-effective. Small- to medium-size buildings, primarily administration buildings built in 

the 1960s-1970s, are likely to be cost-effective for GSHP retrofits. Closed-loop systems were not 

cost-effective at any building except the recreational support facilities that uses electric heating 

and cooling. 

Open-loop systems require a water source and sink. The source can be a well or open body of 

water; the sink can be a secondary well, the same or alternate body of water, or a storm drain. 

Water volume requirements are typically 1.5–3.0 gallons/minute per cooling ton. This

requirement may affect the feasibility of the system. Local codes and regulations may also affect 

feasibility, as many areas do not want to risk groundwater depletion or contamination. 

DoD also conducted an analysis of GSHPs at DoD facilities.

14 That analysis found that GSHPs

are most commonly used in DoD family housing in the eastern half of the United States, where 

they are most cost-effective. GSHPs have not been widely used in other areas of the country. 

Modeling indicates, however, that vertical-bore GSHP systems installed with conventional 

HVAC equipment would be cost-effective in the Mountain West. The analysis found that 

vertical-bore systems alone were generally not cost-effective, although this depends on sitespecific conditions. 

If Fort Carson installed GSHPs in all buildings that use individual building heating systems 

(rather than heat from the central heat plant), the potential savings would be 378,391 

MMBtu/year. If we assume 9% of these installations are cost-effective (based on PNNL’s 

assessment), the potential cost-effective savings would be 34,055 MMBtu from 1,633 tons of 

GSHP. 

6.9.4 Recommendations

Based on the analyses by NREL, PNNL, and DoD, it appears that GSHPs may be cost-effective 

as retrofits in selected buildings. We recommend evaluating GSHPs for any building where 

boilers need replacing. We also recommend evaluating GSHPs in new construction, where 

GSHPs may be more economical because ground loops can be installed at the same time as the 

digging of the foundation and because the GSHP system reduces the size of other HVAC 

equipment. 

6.10 Daylighting

6.10.1 Technology Overview

A complete daylighting system consists of apertures (skylights) to admit and distribute solar light 

and a controller to modulate artificial light in order to achieve energy cost savings. Daylighting 

requires no scheduled maintenance, although skylights may add to roof maintenance. 

Daylighting is screened by using a site’s solar illuminance values (from our GIS resource 

database) to determine the optimum amount of skylight area (as a percentage of total roof 

 

14 Office of the Deputy Under Secretary of Defense (Installations and Environment). Ground Source Heat Pumps at 

Department of Defense Facilities. January 2007. 
74 

area).We balance savings from reduced electric light usage against the cost of installing a 

daylighting system and the expense of heat loss through the skylights. 

6.10.2 Economic Analysis

Table 27 shows an economic analysis of retrofitting daylighting in existing buildings. 

Table 27. Daylighting Economic Analysis

Daylighting Office Skylight/Floor Area Ratio 5%

Total Skylight Area (ft

2

) 770,000 

Annual Electric Savings (kWh/year) 19,057,357 

Annual Natural Gas Savings (therms/year) (299,703)

Total Annual Savings (MMBtu/year) 35,053

Daylighting Capital Cost ($) $115,740,394 

State Tax Credit ($) $ -

Federal Tax Credit ($) $ -

Rebate ($) $ -

Daylighting Cost with incentives ($) $115,740,394 

Daylighting Annual Cost Savings ($/year) $787,436 

Daylighting Payback Period (years) 147 

6.10.3 Recommendations 

The NREL analysis shows that retrofitting daylighting in most existing buildings is not costeffective. There may still be some opportunity for cost-effective installation in warehouse-type 

buildings with uninsulated metal roofs, but for other building types, retrofitting is generally not 

cost-effective. Daylighting, however, can be incorporated at no additional cost in the design 

stage of a building, so we recommend that all new construction at Fort Carson incorporate 

daylighting strategies. 

6.11 Waste-to-Energy

6.11.1 Technology Overview

Waste-to-energy generates energy through incineration of municipal solid waste (MSW). There 

are several technologies for converting MSW to energy. Mass burn, the most common, directly 

combusts MSW as a fuel with minimal processing. Refuse-derived fuel (RDF) pre-processes 

waste into pelletized fuel and then burns it on its own or co-fires it with other fuels (like coal). In 

pyrolysis or thermal gasification, waste is decomposed at a high temperature with little or no 

oxygen in order to generate a producer gas, which can then be combusted to generate heat and 

electricity in a boiler or combustion turbine. Pyrolysis technology is still under development. 

Challenges for WTE include disposal of possibly hazardous ash residue and controlling air 

pollution. 
75 

6.11.2 Economic Analysis

Fort Carson generates about 8,778 tons of municipal solid waste per year, which is currently 

delivered to off-site landfills. NREL conducted an analysis to evaluate the economic viability of 

burning this waste in an on-site waste-to-energy facility in order to generate electricity. This

action would produce renewable electricity for Fort Carson and reduce the burden on local 

landfills. Table 28 presents the results. 

Table 28. Economic Analysis of Waste-to-Energy Plant

Plant Characteristics

Annual MSW resource (tons/yr) 8,778

Availability 90%

Capacity (tons/day) 27

Electric Generating Capacity 

(kW/TPD)

25

Electric Generating Capacity (kW) 670

Parasitic Load (%) 15%

Net to Grid (kW) 570

Operating Hours (hr/day) 24

Initial Cost

Capital Cost ($) $11,960,000 

Federal Tax Credit $3,229,200 

Total Initial Cost $8,730,800 

Revenues

Avoided Cost of Disposal ($/ton) 30

Annual Avoided Cost of Disposal ($) $263,340 

Electric Rate ($/kWh) 0.05

Annual Utility Savings $224,694 

Recovered Materials (%) 3%

Sale of Recovered Materials ($/ton) 175

Annual Recovered Materials income 

($)

$46,085 

Total Annual Revenues $534,119 

Expenses

Operating Costs ($/ton) 131

Annual Operating Costs ($) $1,149,918 

Total Annual Expenses $1,149,918 

Payback

Simple Payback Negative

The NREL analysis shows that low tipping fees and relatively low electric rates make a WTE 

project uneconomical at Fort Carson. 
76 

A larger WTE plant could improve the economics of the project. Relative labor costs for this 

project are high because running a plant requires a minimum number of employees. The plant 

analyzed requires 14 staff, which is similar to the number required for a plant five times its size.

A larger plant would involve lower labor costs on a $/MW basis, but it would be necessary to 

import MSF fuel from off-base landfills. PNNL’s 2008 study found that combining Fort Carson 

waste with the much larger waste stream (300,000-400,000 tons/years) from either the Fountain, 

Midway, or Colorado Springs landfills would fuel a 40-46 MW combustion plant with payback 

periods of seven to nine years (using 2008 utility rates). 

6.11.3 Recommendations 

The NREL analysis found that a WTE plant using only on-site waste would not be economically 

viable. If Fort Carson is interested in pursuing a WTE plant, we recommend assessing the 

feasibility of bringing off-site waste onto the post. A successful project would require a large 

amount of coordination and cooperation between the base and the cities of Fountain and 

Colorado Springs, both of which operate local landfills. 

6.12 Landfill Gas

6.12.1 Technology Overview

Previously we discussed burning waste to generate energy. It is also possible, however, to 

generate energy through the anaerobic decomposition of carbon-based waste streams deposited 

in a landfill. This landfill gas is primarily composed of methane and carbon dioxide. Typically a 

gas handling system at the landfill traps, collects, and transports the gas produced. It is often 

necessary to clean up landfill gas prior to combustion in order to remove potentially hazardous 

compounds such as sulfur. Once a landfill is capped and closed off, it will continue to produce 

gas for 15-20 years. 

A good candidate for landfill gas collection should have at least 1 million tons of waste in place, 

be at least 30 feet deep, and be active or recently closed. It should also have a high organic 

content, because non-organic waste does not break down and emit methane. 

6.12.2 Analysis

Fort Carson has three closed MSW landfills and nine closed construction and demolition (C&D) 

landfills on-site. The C&D landfills are not appropriate for landfill gas collection because most 

of the waste is not organic. We found the MSW landfills to be too small, shallow, and old to 

produce landfill gas. 

There are several larger active landfills in the area outside the base. NETL’s alternative methane 

fuel resource database shows there are four landfills within a 15 mile radius. These facilities have

an estimated total energy value of 793,873 MMBtu and estimated power potential of 12.52 MWe

(see Figure 27). These off-site landfills would not provide an on-site source of renewable energy. 

However, if landfill gas were generated at these sites and treated to reach pipeline quality, it 

could be placed in CSU’s natural gas distribution network. Fort Carson could then utilize natural 

gas directly from the pipeline, but would be, in fact, purchasing the renewable landfill natural 

gas. This arrangement would provide a renewable fuel source for Fort Carson’s boilers or future 

fuel cells or microturbines. 
77 

Figure 27. Landfills near Fort Carson (Credit: Craig Hustwit, ORNL)

PNNL’s analysis15 suggests that these area landfills have very low moisture content and typically 

are not lined, indicating low methane generation, so collecting the gas and then piping it to Fort 

Carson may not be a viable option. 

6.12.3 Recommendations 

We recommend discussing offsite landfill gas generation projects with CSU and local landfill 

owners to evaluate whether local landfills are appropriate for landfill gas systems and if it is 

feasible to pipe gas to Fort Carson. 

6.13 Anaerobic Digestion

6.13.1 Technology Overview

Anaerobic digestion is the conversion of wet biomass feedstocks such as confined animal waste, 

industrial effluent, or wastewater to methane fuel. Because of its high water content, it is not 

efficient to transport wet feedstocks. Instead, they must be converted on site where they are 

generated. 

 

15 Chvala, W.D.; Solana, A.E.; Sates, J.C.; Warwick, W.M.; Weimar, M.R., Reilly, R.W., and Dixon, D.R. 

Renewable Energy Opportunities at Fort Carson, Colorado. PNNL-18132. Pacific Northwest National Laboratory: 

December 2008.
78 

6.13.2 Analysis

Fort Carson’s only on-site source of wet feedstock is a small wastewater treatment plant, which

is too small to make an energy generation project worthwhile. There is a larger wastewater 

treatment plant in the city of Colorado Springs, five miles north of Fort Carson. With a flow of 

30 million gallons per day, this plant could generate enough methane to produce about 27,803 

MMBtu/year or 0.93 MWe. Like the landfill gas discussed earlier, it might be possible to treat 

this gas to pipeline quality, place it in CSU’s natural gas distribution network, and have Fort 

Carson purchase it to displace conventional natural gas. This arrangement would provide a 

renewable fuel source for Fort Carson’s boilers or future fuel cells or microturbines. 

6.13.3 Recommendations 

We recommend discussing offsite methane gas generation projects with CSU and the City of 

Colorado Springs. 

6.14 Hydropower

There is a small dam on the east side of Fort Carson near Fountain, but it would only provide 

enough power for five homes, and therefore is not worth developing. No other hydro resources 

exist at the base. 

6.15 Additional Strategies to Reduce Load and Footprint

6.15.1 Purchase Renewable Energy Certificates (RECs)

The purchase of offsets or credits could enable Fort Carson to achieve a 100% renewably 

powered status. REC purchases are an alternative strategy, but would not contribute to energy 

security at the site. 

6.15.2 Demand Response

An additional option that Fort Carson may want to consider for its facilities is undertaking 

demand response contracts with CSU. Demand response is the lowering of electrical load during 

peak usage. By signing up with CSU as a demand-response provider, Fort Carson would gain 

additional revenue to fund its energy projects and would receive free advanced metering 

infrastructure. Demand response should be a particularly intriguing strategy if Fort Carson has 

electrical loads that it can reduce during peak demand two to three times per year, or is able to 

utilize its backup generators during demand response events. 
79 

7 Transportation Assessment

This section analyzes options for reducing fleet vehicle fuel consumption through vehicle 

replacement, fleet size reduction, or alternative fuel use.

7.1 Fleet Composition and Fuel Use

Fort Carson’s fleet includes 520 vehicles, dominated by vans, SUVs, and pick-up trucks, as 

Table 29 shows. 

Table 29. 2009 Fleet Summary by Vehicle Type and Fuel Type

Vehicle Type Gasoline Diesel E85 CNG Hybrid Total

Van 83 3 50 29 - 165

SUV 10 - 80 - 32 122

Pick-up 51 24 38 11 - 124

Sedan - - 21 - 6 27

Bus - 32 - - - 32

Heavy Truck - 11 - - - 11

Ambulance - 5 - - - 5

Other 24 10 - - - 34

Total 168 85 189 40 38 520

The majority of the fleet uses traditional gasoline or diesel fuel, but a significant number of 

vehicles are flex fuel vehicles (FFVs) that can be fueled by E85. The remainder of the fleet is 

comprised of Compressed Natural Gas (CNG) and hybrid vehicles. 

Fort Carson was unable to provide fleet fuel consumption data to NREL. Instead, we estimated 

2009 fleet fuel use from the reported mileage of each vehicle and the vehicle class EPA mile per 

gallon rating (see Figure 28). Fort Carson personnel say E85 FFVs use E85 nearly exclusively, 

so we assumed that FFVs were always fueled by E85. The fleet uses approximately 276,500 

gallons of fuel each year. 
80 

Figure 28. 2009 fleet fuel use estimates (gallons) 

Given the relatively small number of sedans in the fleet, there may be an opportunity to 

downsize to smaller more fuel efficient vehicles and move away from large pick-ups and SUVs 

where the mission does not dictate a need for these larger vehicles. If there are instances where a 

vehicle is used primarily for passenger transportation, a small sedan may well meet the fleet 

needs. Moving from an older large truck to a compact sedan can halve fuel consumption for that 

vehicle. Likewise, moving from a large four-wheel drive SUV to a small two-wheel drive SUV 

can produce a significant efficiency gain.

Fort Carson possesses a significant number of Neighborhood Electric Vehicles (NEVs) that are 

not captured in the fleet inventory. The NEVs at Fort Carson represent an opportunity for 

reducing fleet fuel use, but their success has been limited by significant constraints compared to 

a traditional vehicle. NEVs have a maximum speed typically of 25 miles per hour, which can be 

viewed as too slow on major roads. The vehicles do not have the comforts of climate control or 

the ability to handle severe road conditions. Even with these constraints, NEVs are 

recommended for campus settings where the distance traveled is small, when traffic is light, and 

when weather conditions are not severe. If NEVs are used in targeted settings they can provide 

significant petroleum displacement. 

7.2 Fleet Utilization Rates

The Fort Carson fleet includes a large number of underutilized vehicles as Figure 29 shows. 

Suggested standard minimum utilization rates for federal fleets range from 7,500 to 12,000 miles 

per year, depending on vehicle classes. Fort Carson has received a waiver from the Department 

of the Army to use reduced utilization rates of 300 miles a month or 3,600 miles per year, due to 

the specific mission needs of the installation. However, one-third (33%) of the vehicles in the 

Fort Carson fleet in 2009 appear to have driven less than the reduced 3,600 mile annual rate. 

126,152 

77,799 

53,051 

19,497 

E85 Gasoline Diesel CNG 
81 

Figure 29. 2009 vehicle utilization

Fort Carson vehicles have low mileage due to infrequent use or short driving distances. In some 

instances, a vehicle may be required to support an infrequent highly important mission such as 

emergency response. In other cases, individual organizations may have an assigned vehicle that 

is infrequently used. In these cases a vehicle pool available across organizations may provide the 

necessary transportation access for all organizations, with fewer total assets. NREL has learned 

that Fort Carson has had some success with this model, and further opportunities for efficiencies 

through vehicle pools may exist. 

Fort Carson primarily leases its fleet vehicles from GSA and they carry a significant monthly 

lease cost. Reducing the number of vehicles in the fleet might free up budget dollars for other 

fleet needs. As an example, a preliminary analysis of vehicles that could be up for replacement 

by GSA in the current year showed that 44 vehicles representing nearly $150,000 in annual lease 

costs were driven less than 300 miles a month. If these vehicles were turned in and not replaced, 

the fleet could free up money to support other initiates, such as implementing alternative fuel 

infrastructure or an electric vehicle pilot program. 

The Fort Carson fleet has a sizeable number of alternative fuel vehicles (AFVs) dominated by 

E85 FFVs, but which also includes a number of CNG and hybrid electric vehicles. NREL was 

informed that the installation has been successful in consistently fueling its FFVs with E85 

available at on-site fueling centers. Without accurate fuel use data, it is not possible to know for 

sure, or to track progress, but the FFVs represent a significant opportunity to reduce petroleum 

consumption. For the purposes of associated mandates, E85 is considered a 100 percent 

alternative fuel, and therefore vehicles fueled by E85 represent a 100% petroleum displacement.

The CNG vehicles in the fleet are late in their lease term and may be up for replacement soon. It 

was not clear whether or not CNG is readily available to fleet vehicles. If CNG is available it 

 - 

50 

100 

150 

200 

250 

300 

350 

400 

450 

Sedans Light Trucks MD & HD 

Trucks

Vehicles

Vehicle Segment

Above Standard Rate Below Standard Rate

Below 3,600 miles
82 

represents a good opportunity for petroleum displacement, particularly in medium and heavy 

duty applications. 

Fleet HEV acquisitions have risen in recent years. Depending on how the HEVs are used, the 

associated petroleum displacement can vary. If the HEV is driven at low speeds the efficiency 

gains are higher than if the vehicle is used more for highway driving. While HEVs use less 

petroleum than a traditional vehicle, they are fueled by petroleum are more expensive than 

traditional vehicles. Other AFV technologies can reach larger petroleum displacements at a 

lower cost.

The fleet also contains a sizeable number of diesel vehicles focused in larger medium and heavy

duty applications. These vehicles represent an opportunity to implement a biodiesel program on 

the installation or in coordination with the surrounding community. 

7.3 Recommendations

The NREL assessment produced the following recommendations: 

• Track fleet fuel use. As mentioned, our analytic team did not receive data on Fort 

Carson’s non-tactical fleet fuel, which presumably the base does not track or manage. 

This circumstance is problematic for a variety of reasons, including the requirement 

of the Army annually to report progress in meeting statutory mandates for the 

increased use of alternative fuel and the reduction of petroleum use. An internal fuel 

use tracking and reporting audit at Fort Carson would be beneficial, and would 

establish ownership of fuel use data management responsibilities. At a minimum, for 

purposes of meeting the mandates, the fleet should track the annual total gallons of 

each fuel type used per vehicle. Higher levels of detail would then improve the ability 

of the fleet to analyze and manage fuel use.

• Right-size the fleet. Fort Carson appears to have an opportunity to reduce the total 

number of vehicles in the fleet. During the annual lease vehicle ordering process, 

low-use vehicles should not be replaced. The base could then allocate the significant 

annual budget dollars saved from not leasing a vehicle to other fleet needs. A vehicle 

pool available across organizations can more efficiently meet the needs of the fleet 

with fewer total vehicles.

o Base managers should align the vehicle fleet composition to the mission of 

each vehicle. During the annual lease vehicle order process, the vehicle of 

choice should be the most fuel efficient vehicle to meet the mission needs. If 

passenger transportation is the primary mission, managers should consider 

fuel efficient sedans and vans. They should consider NEVs in targeted 

settings, particularly where travel distances are small. They should consider 

large SUVs and pick-ups only when the mission requires their capabilities. 

More fuel efficient two-wheel drive options with the same cargo capacity as 

four-wheel drive options should first be considered when missions do not 

include off-road driving. The base can achieve significant reductions in 

petroleum consumption by using the most fuel efficient vehicle for the 

mission. 
83 

• Acquire alternative fuel vehicles. Fort Carson is fortunate to have E85 available on 

the installation. The fleet has been aggressive in expanding its use of E85 and should 

continue this practice. As vehicles are cycled through the lease process, base 

managers should continue to consider FFVs as replacements. Many of the current 

gasoline and diesel vehicles in the fleet could have FFV alternatives available during 

the ordering process. If CNG is available to the fleet, the base should continue to use 

it. CNG vehicles may be particularly successful when considering replacements for 

medium and heavy duty applications.

• Use alternative fuel. Operating FFVs provides an opportunity to reduce petroleum 

consumption. The fleet should take advantage of this opportunity by fueling FFVs 

with E85 every time the vehicles are fueled. 

o The fleet should consider a biodiesel program for the diesel vehicles on post. 

Typically biodiesel is used in the form of B20, a blend of 20% pure biodiesel 

with 80% traditional petroleum diesel. Yet, vehicles that use biodiesel should 

run biodiesel 100% of the time, and fuel storage tanks must be cleaned prior 

to storing biodiesel. Biodiesel specs are in place to ensure a certain quality of 

biodiesel fuel. The DoD and the Marine Corps in particular have had great 

success with biodiesel fuel use. Fort Carson should be able to attain similar 

successes.

o Nearly half of the Fort Carson fleet uses traditional gasoline or diesel, 

consuming an estimated 130,000 gallons of petroleum annually. Not all 

traditional petroleum vehicles have an available E85 FFV as a replacement, 

but it is not unreasonable to expect that half of the remaining gasoline vehicles 

could be replaced by a FFV. Consistently fueling these new FFVs with E85

would displace nearly 40,000 gallons of gasoline consumption. Consistently 

using biodiesel in the diesel vehicle fleet would displace another 10,000 

gallons of petroleum. This scenario could far exceed federal mandates to 

reduce petroleum use 30% by 2020 from a 2005 baseline. 

• Hybrids and electric vehicles. HEVs should be primarily considered for those 

instances where other AFV technologies are not available to meet the mission. HEVs 

do reduce petroleum consumption, but other AFV technologies have the potential for 

a much larger petroleum displacement at a lower cost.

o Electric vehicles are beginning to be available to fleets and represent an 

opportunity for a 100% petroleum displacement. These vehicles do have 

limitations, including a limited range and potentially lengthy recharging times. 

Fort Carson should target specific applications that account for these 

limitations if the technology is to have the most success (see Appendix A for 

additional detail regarding the use and infrastructure requirements of electric 

vehicles).

7.4 Other Transportation Energy

Fuel for the Federal fleet makes up only a small portion of transportation energy used at Fort 

Carson. Figure 30 shows that tactical fuel and commuter fuel use actually account for most of the 

base’s transportation fuel use. 
84 

Figure 30. 2009 Fort Carson fuel use estimates by segment

Examination of these fuel uses was out of the scope of the NZEI analysis; however, we provide a 

few suggestions below for potentially reducing fuel use from these sources. 

7.4.1 Commuter Fuel Use

NREL estimates Fort Carson commuter fuel use to be 7 million gallons of gas annually. We base 

this estimate on assumptions of 28,000 commuters driving an average of 10 miles one way to the 

installation at an average efficiency of 20 miles per gallon for 250 days. Even with sizeable 

fluctuations in assumptions, commuter fuel use at Fort Carson dwarfs fleet fuel use. Reducing 

commuter fuel use by 5% would displace 350,000 gallons of petroleum, which would more than 

exceed the amount of fuel used by the fleet.

NREL did not investigate whether or not Fort Carson has an initiative in place to reduce 

commuter fuel use. If commuter fuel reduction policies are in place, the recommendations to 

follow may be redundant. (See Appendix A for additional information regarding the impact of 

electric vehicle adoption on commuter trends.) 

• Alternative work schedules/locations. Alternative work schedules may allow 

commuters an option to take every other Friday off or work from home one day a 

week. The alternative schedules would reduce the number of commuter trips and thus 

reduce petroleum consumption. 

• Ride sharing. A formal ride sharing program may help to maximize the number of 

commuters participating. One approach is to e-mail all employees asking for 

volunteers of who might be interested in sharing rides to and from work. Interested 

parties would provide their address information, and would be matched with other 

personnel living nearby.

7M

1M

0.3M

2009 Fuel Consumption (Gallons)

Commuter Tactical Fleet
85 

• Idle reduction. The large number of daily commuters to Fort Carson may create long 

wait times at the entrance gates. Allowing for staggered employee daily start times 

could reduce the congestion and the need for commuter vehicles to idle at the gates. 

7.4.2 Tactical Fuel Use

The tactical fuel use represents a significant portion of all transportation fuel used at Fort Carson. 

We recommend that NREL conduct additional analysis on the potential for reduced tactical fuel 

use based on efficiencies. NREL has supported DoD extensively in the past, and understands the 

unique challenges and opportunities faced by the military services. We would welcome the 

opportunity to work with DoD personnel in identifying potential operational efficiencies, and in 

lobbying for additional support for the military when it is clear that the services are underresourced. 
86 

8 Microgrid Assessment and Recommendations

While the majority of this report focuses on opportunities for achieving a net zero installation 

tied to the utility grid, at times the utility grid may become unavailable. When this happens, the 

military base must provide backup power to its own critical loads. If utility service is lost for a 

significant amount of time, it may be desirable to operate Fort Carson as a self-contained 

distribution system known as a microgrid. Operating as a microgrid requires extensive planning, 

and equipment must be specially configured to operate correctly in the absence of the utility grid. 

In coordination with this study, Sandia National Laboratory (SNL) is evaluating microgrid

design options. Traditionally, microgrid emergency back-up systems consist of a set of 

dispatchable, fossil-fuel driven generation sources, such as diesel generators. This analysis looks 

at the benefits of using the renewable energy sources at Fort Carson to complement or replace a 

diesel generator backup system. 

8.1 Critical Load Profile

Fort Carson worked with SNL to identify its critical mission facilities, and subdivided them into 

principal and secondary buildings. Designated facilities primarily included headquarters and 

communication buildings. The hospital and wastewater treatment plant, which are also 

considered critical, were not included in this analysis because their location makes it impractical 

to tie them into the microgrid. The critical load in the primary and secondary buildings was 

estimated based on existing backup generator capacity at each building, as Table 30 shows. 

Table 30. Critical Load

Building

Diesel Backup 

Generator 

Size (kW)

Principal Critical Loads

Bld. 1014 160

Bld. 1118 475

Bld. 1430 500

Bld. 1435 1,250

Bld. 1550 1,000

Secondary Critical Loads

Bld. 1525 50

Bld. 1444, 1526, and 1829 0

Total 

Peak Critical Load 

Primary + Secondary 3.0-4.0 MW

We used the original load profile to model the critical load profile. Since the original load profile 

included energy generation from the 2 MW PV array, we added the hourly solar PV production 

back into the base load. We then scaled down this profile to have a peak critical load equal to the 

critical primary and seconday peak loads. 
87 

8.2 Model Assumptions

NREL used the HOMER modeling tool to optimize energy sources for the microgrid, including 

the following power generation sources in the optimization:

• Diesel Generator

o Three diesel 1 MW-1250 kVA Caterpillar gensets are modeled to provide 

backup power. Figure 31 shows the genset efficiency curve. 

Figure 31. Genset fuel efficiency curve

o The average efficiency is approximately 38%. The minimum allowable load 

on the generator was set to 10% of its rated capacity, as a conservative 

estimate. This means that if the load falls below 10% of the rated capacity, the 

generators will continue to run at the minimum rate. If PV and/or batteries are 

able to meet the entire critical load, the generators will shut off.

o Fuel Cost. According to the U.S. Government’s Energy Information 

Administration16 the average price for diesel is $2.85/gal ($0.75/liter). 

o Capital and O&M cost. The capital cost used in the model is $400/kW for a 

total capital cost of approximately $1,200,000 for the 3 MW generation. 

Maintenance cost is estimated to be $8.53/hour and is dependent on the hours 

of operation and the percentage of full load that it serves. 

• Flow Battery. Flow batteries (utility scale rechargeable batteries that use electrolytes 

for converting stored chemical energy into electricity) reduce the use of diesel and 

store the energy from the PV and wind. We modeled the ZBB energy corporation 

flow battery in HOMER with a capital cost of $100,000. The nominal capacity is 500 

Ah with round trip efficiency of 72%. The life time of the flow battery is 30 years; the 

cell stack lifetime is 10 years. 

• Hybrid Electric Vehicles (HEV) Battery. HEV batteries can also provide storage on 

the microgrid. The HEV module designed for this analysis represents a bank of 

batteries distributed across 20 all-electric trucks slated to become part of the Fort 

 

16 Energy Information Administration. Official Energy Statistics from the U.S Government Site. Weekly Retail OnHighway Diesel Prices ,http://tonto.eia.doe.gov/oog/info/wohdp/diesel.asp. Accessed April 2010. 
88 

Carson Transportation Motor Pool. These are modeled after the Smith Electric 

Vehicle "Newton,"17 each having an 80 kWh battery pack with the capability of 

charging (and potentially discharging) at 20 kW. Based on recent information 

gathered by NREL, we assumed a battery cost of $1,000/kWh for a stationary battery 

system (without the vehicle). 

• Battery performance is modeled by cycle life and charge efficiency. We estimated 

cycle life from Brooker, 2010,18 assuming approximately 20,000 cycle at 10% depth 

of discharge and 2000 cycles at 50% depth of discharge. We based the charge 

efficiency on the internal impedance data from Keyser, 2003.19

• PV. We modeled the capital cost of PV at $6.00/W for capital cost and replacement. 

We assumed a lifetime of 25 years for the array. 

• Wind. We modeled 1.5 MW wind turbines with a capital and replacement cost of $5 

million/turbine. This cost decreases to $4 million/turbine as the number of turbines 

increase; thus, for 20 turbines, the cost would be $80 million. The O&M cost is 

$108,000/year. The expected lifetime of a wind turbine is 15 years. Note that we used 

the lower wind resource near the microgrid area on the north end of base for this 

scenario. 

• Biomass. The biomass generator has a capital cost and replacement cost of $8.75 

million per MW. The non-fuel O&M cost is $446/hour. We assumed the lifetime of 

the generator to be 200,000 hours. The boiler associated with the biomass system has 

an efficiency of 70%. Electrical efficiency is 20%. Natural gas costs $5.44/MMBtu 

and the woody biomass fuel costs $55/ton or $4.50/MMBtu. 

8.3 Results

If only diesel generators were used to support the critical loads, 4.3 MW of diesel generation 

would be required, with a COE of $0.25/kWh. This scenario would use an estimated 1,755,552 

gallons per year of diesel fuel. The optimal solution to meet the critical loads on an islanded 

system is 3.1 MW of biomass, 1 MW of diesel generation, and 500 kW of PV, as Table 31

shows. When biomass and PV replace some of the diesel generation, the COE decreases to 

$0.17/kWh and diesel fuel use drops 93% to 110,258 gallons annually. 

 

17 www.smithelectric.com/ 18Brooker, A.; Thornton, M.; Rugh, J. Technology Improvement Pathways to Cost Effective Vehicle Electrification: 

Preprint. NREL, 2010

19 Keyser, M.; Pesaran, A.; Mihalic, M.; Yu, J.; Kim, S.; Alamgir, M.; Rivers, D. Thermal Characterization of 

Advanced Lithium-Ion Polymer Cells. Advanced Automotive Battery Conference, June 2003.
89 

Table 31. Energy Mix to Meet the Critical Load 

Component Size (MW) Production (kWh/yr) Production (%)

Biomass 3.1 23,349,642 91

Diesel Generator 1.0 1,552,869 6

PV array 0.5 778,655 3

Total 25,681,166 100

Figure 32 shows the monthly power production for the microgrid system.

Figure 32. Monthly power production for microgrid 

Because the microgrid cannot rely on the utility grid as a source or sink for excess power, the 

load and generation must match exactly at all times. While PV and wind were the most costeffective sources of renewable energy in the grid-tied case, their high variability makes them less 

effective on a microgrid. Consistent baseload sources of power, like diesel generation, biomass, 

or CSP are better choices in a microgrid scenario despite their higher cost.

The Fort Carson microgrid modeled here relies mainly on biomass as the cheapest source of 

baseload power. Diesel generation supplements the biomass generator, and provides added 

security in case biomass fuel supplies are disrupted. Other options for consistent power, such as 

flow batteries and HEV batteries are not part of the solution, due to their high cost compared to

diesel or biomass fuel. A small amount of PV offsets some biomass and diesel fuel but, due to 

the variability of PV generation, only a small amount can be incorporated in the microgrid while 

maintaining stability. Wind is no longer part of the solution because the wind resource near the 

microgrid area is poor. 

This solution requires a large amount of biomass fuel that will have to be trucked in from offsite. 

In a long term utility outage, transportation pathways might be disrupted. To reduce reliance on 
90 

outside fuel sources like biomass and diesel, PV or CSP could support the microgrid. The base 

could use diesel backup generators to generate power during extended cloudy periods. 

8.4 Recommendations

If a microgrid at Fort Carson is desired, we recommend a detailed study to determine equipment 

requirements. The above analysis is intended to illustrate the potential benefits of incorporating 

renewable energy sources into a microgrid at Fort Carson. Base personnel should not consider it

sufficient for microgrid planning and operation. 

In addition to the recommended electrical system studies, implementing a microgrid with 

renewable energy, storage, and generators at Fort Carson will require the addition of “smart” 

controls. These controls would allow Fort Carson to manage its distributed resources and 

intentionally island itself from Colorado Springs Utility, in order to ensure the ability to continue 

critical operations during an extended emergency. The sophisticated control system would 

coordinate the electrical generation systems (renewable, storage, and diesel generators) and Fort 

Carson’s critical loads to maintain grid stability. Additionally, the smart control system will 

allow safe reconnection with the utility once the emergency condition has passed. 

In addition to allowing operation as a stand-alone island, the control system would potentially 

allow Fort Carson to participate in local grid support activities such as customer demand 

response. The base might, for example, coordinate adjustable loads such as the charging of fleet 

electric vehicles with CSU in order to ensure that the local grid is not taxed beyond its 

capabilities as the nature of distribution systems and their uses evolve in the future. A control 

system may also interface with building energy management systems to increase the efficiency 

of the distribution system by improving renewable generation and load coincidence. 

The microgrid control system would consist of a central computer system that would receive data 

from a network of sensors strategically placed on critical base infrastructure. The system would 

need high-resolution load monitoring capability and the ability to follow load by dispatching 

generation or rapidly turning on and off generation systems. Additionally, the system would 

require real-time voltage, current, and frequency measurements to ensure the microgrid operates 

within criteria.

Recommended studies for microgrid planning and operation include: 

• Voltage regulation 

• Protection and coordination 

• Voltage stability

• Rotor-angle stability

• Frequency regulation. 

All studies should use actual machine and system parameters and settings. It is important to 

consider and account for impact on system O&M when designing and implementing a microgrid. 
91 

9 Energy Project Recommendations

The overall goal of this assessment is to recommend an optimal energy project strategy that will 

support the installation’s energy goals. Here, we provide two sets of recommendations: 1) 

currently cost-effective projects, and 2) projects to achieve net zero energy. 

9.1 Currently Cost-Effective Energy Projects 

Our analysis found that, based on 2009 energy prices, the following projects would reduce the 

life cycle cost of energy. Implementing these projects would reduce site energy use from 2009 

levels by 30% and source energy use by 33%. 

Table 32. Cost-Effective Energy Projects

Technology Size

Site Energy 

Savings 

(MMBtu)

Source 

Energy 

Savings 

(MMBtu)

Implementation 

Cost ($)

Simple 

Payback 

Period 

(years)

Energy 

Efficiency 20.3% 345,337 632,240 45,356,563 14

Solar 

Ventilation 

Preheating

88,050 

ft

2 26,353 28,777 2,241,277 15

GSHP

1,633 

tons 34,055 16,061 1,138,477a 16

Wind

10.5 

MW 61,304 171,528 13,656,300 16

Total - 455,285 856,887 62,392,617 15

a. Includes avoided cost of conventional heat system replacement

If appropriated funds are not available, we recommend energy load reduction measures including 

energy efficiency, GSHP, and solar ventilation preheating projects, which the base would

implement through an ESPC or UESC contract. We recommend implementation of the wind 

project through a power purchase agreement. 

9.2 Net Zero Energy Projects

To achieve net zero energy status, Fort Carson will need to implement additional energy projects.

Table 33 shows the projects we recommend in order to achieve near net zero energy use by 2015. 

Fort Carson expects growth in energy use to level off by 2015 as new building construction ends, 

so we anticipate that these projects will provide enough energy to achieve near net zero energy 

status in 2015 and beyond. 
92 

Table 33. Recommended Projects to Achieve Near Net Zero Energy In 2015

Size 

(Variable Units)

Site Energy 

(MMBtu)

Electric Energy Project Recommendations

Efficiency 26.70% 203,388

Wind 10.5 MW 61,304

PV-ground mounta

20.2 MW 100,554

PV-rooftop 24 MW 125,580

PV-carport 28.4 MW 120,046

CSP 20 MW 170,600

Total Renewable Electricity 

Production (MMBtu) 781,472

2015 Electricity Use (MMBtu) 781,472

Percent of electric energy 

supplied by renewables 100%

Thermal Energy Project Recommendations

Efficiency 17.20% 266,270

Solar Vent Preheat 119,748 35,841

Solar Hot Water 59,080 28,406

Biomass Heat 30 MMBtu/hr 160,000

GSHP 24,684 514,611

Total Renewable Thermal 

Production (MMBtu) 1,005,128 

2015 Thermal Energy Use 

(MMBtu) 1,143,335

Percent of thermal energy 

supplied by renewables 88%

Transportation Energy Project Recommendations

Replace half of gasoline- fueled 

vehicles with E85 40,000 4,400

Replace diesel with biodiesel 10,000 1,380

Continue current renewable 

fuel use 126,152 11,089 

Total Renewable Fuel Use 176,152 16,869

Total Fuel Use 276499 29403

Percent of fleet energy supplied 

by renewables 57%

a. 2 MW of the required 20.2 MW is already installed at Fort Carson
93 

Figure 33 shows Fort Carson energy sources if recommendations are implemented. 

Figure 33. 2015 energy mix

9.2.1 Electrical Energy

The NREL analysis calls for first reducing electrical energy use through efficiency, using the 

measures outlined in Section 5. To extrapolate efficiency savings to 2015, we assume that 

efficiency reductions implemented in new buildings are equal to efficiency reductions in existing 

buildings. The base would generate remaining electrical energy through a combination of wind, 

PV, and CSP. Our analysis added technologies to the mix in order of economic viability, with 

size limited by land and resource constraints. Our analysis limits wind capacity to 10.5 MW 

based on land available in the high wind area. Ground mount PV and rooftop PV capacity are 

limited based on our assessment of available ground and rooftop area. CSP capacity is also 

limited by land availability. 

Efficiency, 24%

Wind, 3%

PV-ground 

mount, 5%

PV-rooftop, 

6%

PVcarport, 

6%

CSP, 9%

Biomass Heat, 

8%

Solar Vent 

Preheat, 2%

Solar Hot Water, 

1%

GSHP, 26%

Renewable Fleet, 

1%

Non-Renewable 

Fleet, 1%

Natural Gas, 

7%
94 

This analysis did not evaluate the effects of large scale renewable generation on Fort Carson’s 

distribution system. If Fort Carson chooses to pursue installation of large renewable systems, 

staff should analyze the location and tie in point to the distribution systems and perform a 

detailed electrical analysis. This analysis should include vendor specific information such as 

machine impedances, controller modes and settings, and protective devices and set-points. The 

analysis should include the following: 

• Voltage regulation 

• Protection and coordination 

• Voltage stability.

As generation is added to the distribution system, the entire base protection scheme must be 

continually evaluated to ensure proper operation. The distribution protection and coordination 

scheme must be able detect and compensate for the variability of the proposed generation 

sources. 

9.2.2 Thermal Energy

The use of thermal energy is first reduced through efficiency, using the measures outlined in 

Section 5. Remaining requirements for thermal energy would be generated through a 

combination of solar ventilation preheating, solar water heating, ground source heat pumps, 

biomass, and natural gas. To extrapolate to 2015, we assume that savings from efficiency 

reductions and thermal building technologies (solar vent preheat, solar water heat, GSHP) are 

proportional to the savings estimated for existing buildings. 

Our analysis shows that natural gas will remain part of the thermal energy solution, preventing 

Fort Carson from reaching 100% renewable energy. This outcome is primarily due to the 

difficulty of offsetting 100% of heating energy in distributed building systems with renewable 

energy. Options for meeting the remaining thermal energy use with renewable energy include: 

• Install microturbines or fuel cells to heat individual buildings. In order for 

microturbines or fuel cells to be renewable, Fort Carson would need to use a 

renewable fuel, such as biogas from a landfill or wastewater treatment plant. We are 

not aware, however, of any sources of biogas currently available in Colorado Springs, 

although sources may be developed in the future. 

• Expand the central heating system. Expanding the central heating system would allow 

additional thermal needs to be met through a renewable-fueled centralized system.

Two options are a larger biomass boiler (subject to resource constraints) or a larger 

concentrating solar power system (subject to land availability). 

• Convert to electric heating. The base could supply electric heating energy through 

additional roof-mounted or carport photovoltaics. 
95 

9.2.3 Transportation Energy

Fuel use estimates suggest that if the fleet were to follow the recommendations to convert half of 

the gasoline vehicles to flex fuel vehicles and to implement a biodiesel program, the base could 

see a reduction of roughly 40,000 gallons of gasoline and 10,000 gallons of diesel. Figure 34

shows the recommended fuel use breakdown in gallons for the Fort Carson fleet. 

Figure 34. Fort Carson recommended fuel use breakdown

For renewable fuel accounting purposes, E85 is considered by the Federal Government as a 

100% renewable fuel and B20 biodiesel and as a 20% renewable fuel. 

These recommendations increase fleet renewable fuel use from 38% to 57%. 
96 

10 Implementation: Project Planning and Financial Assessment

10.1 Implementation Options

Fort Carson has a variety of available options for implementing the recommended energy 

projects. The following paragraphs describe these options (note: information on financing 

mechanisms adapted directly from www.femp.energy.gov/financing/mechanisms.html) 

10.1.1 Energy Savings Performance Contract (ESPC)

ESPCs enable Federal agencies to accomplish energy-savings projects without up-front capital 

costs and without special Congressional appropriations. 

An ESPC is a partnership between a Federal agency and an energy service company (ESCO). 

The ESCO conducts a comprehensive energy audit for the Federal facility and identifies 

improvements to save energy. In consultation with the Federal agency, the ESCO designs and 

constructs a project that meets the agency's needs and arranges the necessary financing. The 

ESCO guarantees that the improvements will generate energy cost savings sufficient to pay for 

the project over the term of the contract. After the contract ends, all additional cost savings from 

that time on accrue to the agency. Contract terms up to 25 years are allowed.

The average contract price for a Super ESPC contract undertaken by a Federal agency between 

1998 and 2008 was $15.3 million.

20 Typically ESPC contracts need to be at least $1 million to 

$2 million in size to generate interest from the private sector. 2005-2009 historical data from the 

Super ESPC Awarded Delivery Order Summary21 shows that the average project investment per 

annual MMBtu savings was $131.34. This calculation does not reflect the actual contract price, 

which includes the cost of financing. The average contract price over the last five years was 

$337.28/MMBtu. 

Given such a large difference between the project investment price and the contract price, it is 

worth comparing the implementation option of an ESPC contract with an appropriations-funded 

energy-efficiency investment. It should be noted, however, that the life-cycle costs of 

appropriations-funded projects versus ESPC contracts have been shown to be approximately the 

same, if we include all costs and the longer time cycle of appropriations funding.22 

10.1.2 Utility Energy Services Contract (UESC) 

Another way for Federal agencies to implement efficiency and renewable energy projects is 

through utilities. Federal agencies often enter into UESCs to implement energy improvements at 

their facilities. With a UESC, the utility typically arranges financing to cover the capital costs of 

the project. Then the agencies repay the utility over the contract term, drawing on the cost 

 

20 Federal Energy Management Program. Super ESPC Awarded Delivery Orders Summary. DOE Awarded Task 

Order Report. Awarded Energy Service Performance Contacts. 

www.femp.energy.gov/pdfs/do_awardedcontracts.pdf. Accessed August 24, 2009. 21 Federal Energy Management Program. Super ESPC Awarded Delivery Orders Summary. DOE Awarded Task 

Order Report. Awarded Energy Service Performance Contacts. 

www.femp.energy.gov/pdfs/do_awardedcontracts.pdf. Accessed August 24, 2009. 22 Hughes, P.J.; Shonder, J.A.; Sharp, T.; Madgett, M. Evaluation of Federal Energy Savings Performance 

Contracting-Methodology for Comparing Processes and Costs of ESPC and Appropriations Funded Energy Projects. 

ORNL/TM-2002/150. Oak Ridge, Tennessee: Oak Ridge National Laboratory. 2003. 
97 

savings that the energy efficiency measures generate. Using this arrangement, agencies can 

implement energy improvements with no initial capital investment; the net cost to the Federal 

agency is minimal, and the agency saves time and resources by using the one-stop shopping 

provided by the utility. 

10.1.3 Power Purchase Agreement (PPA)

PPAs allow Federal agencies to finance on-site renewable energy projects while incurring no upfront capital costs. 

With a PPA, a developer installs a renewable energy system on agency property under an 

agreement that the agency will purchase the power that the system generates. The agency pays 

for the system through these power payments over the life of the contract. After installation, the 

developer owns, operates, and maintains the system for the life of the contract. Fort Carson used 

a PPA to finance Fort Carson’s 2 MW solar array, and it would be a good option for future large 

projects.

10.1.4 Appropriations, ECIP, ARRA, Etc. 

Energy projects can also be founded directly through agency or government budget mechanisms. 

For example, the efficiency projects that Fort Carson is currently undertaking will receive their 

funding from either the Energy Conservation Investment Program (ECIP) through the military, 

or from the American Recovery and Reinvestment Act (ARRA) through the Federal 

Government. Funding through these mechanisms has the advantage of reducing project financing 

costs. However, government funded projects are not eligible for the benefits of renewable energy 

generation tax credits. 

10.2 Other Implementation Considerations

10.2.1 Interconnection Requirements 

The ideal way for Fort Carson to connect its distributed energy generation systems to the electric 

grid is through net metering. Net metering reduces Fort Carson’s electric bill by subtracting the 

renewable energy generated from the utility bill. If a renewable energy system generates more 

electricity than the current load, the additional energy can be “stored” on the electric grid to 

offset consumption later. Under Colorado net metering law, municipal utilities like Colorado 

Springs Utility must offer net metering up to 25 kW for commercial and industrial customers.

The limit is applied per meter, and Fort Carson has only one main meter. Colorado Springs 

Utilities has indicated its possible willingness to negotiate a more favorable net metering 

agreement, such as applying the limit on a per building basis for renewable located on buildings 

(like rooftop PVs). Renewable systems sized to provide net zero energy, however, will be well 

above the net metering limit. 

Fort Carson’s larger renewable systems (up to 10 MW) will likely be interconnected under 

Colorado’s interconnection rules, which allow systems up to 10 MW to interconnect to the utility 

grid. Interconnection at this level may require studies involving project scope, feasibility, impact 

and facilities. Fort Carson may incur a portion of the total costs associated with these studies, and 

will be required to pay for liability insurance. 
98 

10.2.2 Incentives

Renewable energy projects at Fort Carson are eligible for CSU solar rebates. Energy projects at 

Fort Carson owned by a third party with tax liability could also be eligible for Federal tax credits 

and accelerated depreciation. In addition, Fort Carson may also choose to sell the renewable 

energy credits (RECs) that would accrue to such projects. Table 34 presents an overview of these 

renewable energy incentives. 

Table 34. Renewable Energy Incentives

Incentive Amount Eligible Technologies

Federal tax 

credit

30% rebate on capital cost PV, CSP, wind, biomass, fuel 

cells, solar vent preheat, solar 

water heat

10% rebate on capital cost GSHP, microturbines

Modified 

Accelerated 

Depreciation

Year 1-0.2; Year 2-0.32; Year 3-

0.192; Year 4- 0.115; Year 5-

0.115; Year 6-0.058 

PV, CSP, wind, biomass, fuel 

cells, solar vent preheat, solar 

water heat, GSHP, microturbines, 

landfill gas, WTE, anaerobic 

digestion

CSU solar 

rebate

$3/watt rebate up to a maximum 

of $75,000 (25 kW)

PV

REC sale Estimated $0.05/kWh for 20 years PV, CSP

Estimated $0.001/kWh for 20 

years

Wind, biomass electric

National Environmental Policy Act (NEPA) 

When planning for and installing energy projects, Fort Carson must be aware of National 

Environmental Policy Act (NEPA) stipulations. NEPA requires Federal agencies to consider the 

environmental impacts of projects. NEPA requirements vary based for each specific project. The 

Act specifies three levels of possible required analysis: 1) categorical exclusion, 2) 

environmental assessment, and 3) an environmental impact statement.23 Building energyefficiency upgrades, rooftop energy systems such as PV, daylighting, and solar hot 

water―because they are modifications to existing facilities―could qualify for categorical 

exclusion. Projects such as ground-mount PV or CSP, however, could require more detailed 

NEPA assessments since they involve disturbing land. Environmental assessment would be 

required to determine if these projects would produce a significant environmental impact. If 

evidence of a significant environmental impact was found, NEPA would then require a more 

detailed environmental impact study. 

10.3 Financial Analysis

This section presents a basic financial analysis of the recommended 2015 solution to 

approaching net zero energy installation status. This analysis simply provides a sample case and 

does not necessarily represent the actual financial costs of these recommendations. The actual 

 

23 National Environmental Policy Act. US EPA, www.epa.gov/Compliance/basics/nepa.html. Accessed April 2010. 
99 

financial costs will be affected by incentive availability, installation year, and energy prices at 

the time of installation, and interconnection options. Assumptions used in this analysis include: 

• Electricity and natural gas use changes from 2010–2015 according to projections 

outlined in Section 3.3.3 (based on building area growth and estimated building EUI). 

From 2015 to 2030, electricity and natural gas use is constant, equal to 2015 use. 

• The annual inflation rate is 1.2%, from NIST’s 2009 Energy Price Indices Analysis 

report. 

• The discount factor is 3%, from NIST’s 2009 Energy Price Indices Analysis report. 

• The electricity price increase from 2010 to 2015 is based on CSU predictions of 

12%/year (see Section 3.4). From 2016 to 2050, electricity prices escalate at 

2.2%/year (1% above inflation). 

• Natural gas prices escalate at 2.2%/year (1% above inflation). 

• Annual O&M costs escalate at 1.2%/year (equal to inflation).

• O&M costs for renewable projects are included. No savings in current O&M costs 

due to displaced fossil fuel equipment is accounted for. 

• All RECs are sold, at estimated values of $0.05/kWh for PV and CSP, and 

$0.001/kWh for wind for 40 years.

• Energy efficiency implementation cost is estimated at $131.34/MMBtu saved based 

on the Super ESPC Awarded Delivery Order Summary24 that details the cost of 

energy savings for Federal ESPC contracts. The data utilized was the average project 

investment per annual MMBtu savings from the years 2005 to 2009. This calculation 

does not reflect the actual contract price, which includes the cost of financing. 

• All investments are funded through government appropriations and owned by the 

government. Therefore, Federal tax credits are not included. If funded through private 

parties (ESPCs or PPAs, for example), a project could claim Federal tax credits 

valued at $177M (25.5% of initial cost). However, financing and markup rates 

associated with private ownership might negate savings from tax credits. We 

recommend additional analysis to evaluate financing alternatives.

• Project lifetime is 40 years.

• All energy is “net metered,” meaning the energy is sold to and purchased from the 

utility at the same rate.

• Utility standby and departing load charges are not included. 

• The cost implications of fleet fuel switching were not analyzed.

 

24 Federal Energy Management Program. Super ESPC Awarded Delivery Orders Summary. DOE Awarded Task 

Order Report. Awarded Energy Service Performance Contacts. 

www.femp.energy.gov/pdfs/do_awardedcontracts.pdf. Accessed August 24, 2009. 
100 

• To simplify the analysis, all capital costs are modeled to occur in the first year and 

full energy savings are realized immediately. In reality, implementation would likely 

occur over several years.

Table 35 shows the components of the initial capital investment, annual O&M cost, rebate, and 

REC payment. Note that the rebate is not included in the financial analysis. 

Table 35. Initial Cost, O&M, Rebate, and REC Sale Components

Size Initial Cost ($)

O&M 

($/yr) Rebate ($)

REC Sale 

($/yr)

Efficiency 26.70% 61,684,882 0 0 0

Wind 10.5 MW 19,509,000 216,000 5,852,700 17,967

PV-ground mount 20.2 MW 101,000,000 176,824 30,300,000 1,473,590

PV-rooftop 24 MW 144,000,000 238,368 43,200,000 1,822,800

PV-carport 28.4 MW 213,000,000 282,069 63,900,000 1,757,960

CSP 20 MW 184,000,000 1,750,000 55,200,000 2,500,000

Biomass Heat 30 MMBtu 10,000,000 75,000 3,000,000 0

Solar Vent Preheat 119,748 ft

2 3,048,137 - 914,441 0

Solar Hot Water 59,080 ft

2 4,116,429 20,582 1,234,929 0

GSHP 24,684 tons 61,710,000 0 6,171,000 0

Total 842,068,447 2,960,593 221,773,070 7,596,869 

Table 36 shows the financial analysis. The project requires a capital investment of $842 million.

It takes 35 years to recoup the initial investment. The net present value after 40 years, without 

Federal tax rebates, is $96 million. The results from this analysis illustrate that if fossil energy 

prices rise as predicted, the near net zero energy project recommendations would provide 

reduced energy costs to the base over a 40 year lifetime. This analysis, however, is highly 

dependent on future fossil energy prices. If fossil energy prices increase at a lower rate than 

predicted, net present value could become negative. 
101 

Table 36. Financial Analysis of 2015 Near Net Zero Recommendations

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Expenditures

Capital Cost 842,068,447 

Annual O&M 2,960,593 2,996,120 3,032,074 3,068,459 3,105,280 3,142,544 3,180,254 3,218,417 3,257,038 3,296,123 

Natural Gas 1,028,376 1,084,008 1,115,371 1,171,526 1,206,748 1,218,065 1,244,863 1,272,250 1,300,239 1,328,844 

Total 846,057,417 4,080,129 4,147,445 4,239,985 4,312,028 4,360,609 4,425,117 4,490,667 4,557,277 4,624,967 

Revenues

Utility Electric 

Savings 9,800,999 11,367,903 13,160,218 15,563,064 18,061,230 20,552,521 21,004,676 21,466,779 21,939,048 22,421,708 

Utility Thermal 

Savings 7,541,425 7,949,395 8,179,387 8,591,194 8,849,483 8,932,479 9,128,993 9,329,831 9,535,087 9,744,859 

REC Sale 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 

Total 24,914,741 26,889,615 28,911,922 31,726,575 34,483,030 37,057,317 37,705,987 38,368,927 39,046,453 39,738,884 

Net Savings

Net Savings (821,142,676) 22,809,486 24,764,477 27,486,590 30,171,003 32,696,708 33,280,870 33,878,261 34,489,176 35,113,917 
102 

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Expenditures

Annual O&M 3,335,676 3,375,704 3,416,213 3,457,207 3,498,694 3,540,678 3,583,166 3,626,164 3,669,678 3,713,714 

Natural Gas 1,358,079 1,387,957 1,418,492 1,449,699 1,481,592 1,514,187 1,547,499 1,581,544 1,616,338 1,651,898 

Total 4,693,755 4,763,661 4,834,704 4,906,906 4,980,286 5,054,865 5,130,665 5,207,708 5,286,016 5,365,612 

Revenues

Utility Electric 

Savings 22,914,985 23,419,115 23,934,335 24,460,891 24,999,030 25,549,009 26,111,087 26,685,531 27,272,613 27,872,610 

Utility Thermal 

Savings 9,959,246 10,178,350 10,402,273 10,631,123 10,865,008 11,104,038 11,348,327 11,597,990 11,853,146 12,113,915 

REC Sale 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 

Total 40,446,548 41,169,781 41,908,926 42,664,331 43,436,355 44,225,364 45,031,731 45,855,838 46,698,076 47,558,843 

Net Savings

Net Savings 35,752,793 36,406,121 37,074,221 37,757,425 38,456,070 39,170,499 39,901,066 40,648,130 41,412,060 42,193,231 

2030 2031 2032 2033 2034 2035 2036 2037 2038 2039

Expenditures

Annual O&M 3,758,279 3,803,378 3,849,019 3,895,207 3,941,949 3,989,253 4,037,124 4,085,569 4,134,596 4,184,211 

Natural Gas 1,688,239 1,725,381 1,763,339 1,802,132 1,841,779 1,882,298 1,923,709 1,966,031 2,009,283 2,053,488 

Total 5,446,518 5,528,759 5,612,358 5,697,339 5,783,729 5,871,551 5,960,833 6,051,600 6,143,879 6,237,699 

Revenues

Utility Electric 

Savings 28,485,808 29,112,495 29,752,970 30,407,536 31,076,501 31,760,184 32,458,909 33,173,004 33,902,811 34,648,672 

Utility Thermal 

Savings 12,380,421 12,652,791 12,931,152 13,215,637 13,506,382 13,803,522 14,107,199 14,417,558 14,734,744 15,058,908 

REC Sale 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 

Total 48,438,546 49,337,603 50,256,439 51,195,490 52,155,200 53,136,023 54,138,425 55,162,879 56,209,872 57,279,898 

Net Savings

Net Savings 42,992,028 43,808,845 44,644,082 45,498,151 46,371,471 47,264,472 48,177,592 49,111,279 50,065,992 51,042,199 
103 

2040 2041 2042 2043 2044 2045 2046 2047 2048 2049

Expenditures

Annual O&M 4,234,422 4,285,235 4,336,658 4,388,698 4,441,362 4,494,658 4,548,594 4,603,177 4,658,415 4,714,316 

Natural Gas 2,098,664 2,144,835 2,192,021 2,240,246 2,289,531 2,339,901 2,391,379 2,443,989 2,497,757 2,552,707 

Total 6,333,086 6,430,070 6,528,679 6,628,943 6,730,893 6,834,559 6,939,973 7,047,166 7,156,172 7,267,024 

Revenues

Utility Electric 

Savings 35,410,943 36,189,984 36,986,164 37,799,859 38,631,456 39,481,348 40,349,938 41,237,636 42,144,864 43,072,051 

Utility Thermal 

Savings 15,390,204 15,728,789 16,074,822 16,428,468 16,789,895 17,159,272 17,536,776 17,922,585 18,316,882 18,719,854 

REC Sale 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 7,572,317 

Total 58,373,465 59,491,090 60,633,303 61,800,645 62,993,668 64,212,937 65,459,031 66,732,539 68,034,064 69,364,222 

Net Savings

Net Savings 52,040,379 53,061,020 54,104,624 55,171,701 56,262,775 57,378,378 58,519,058 59,685,373 60,877,892 62,097,198 
104 

11 Conclusion

NREL’s net zero analysis evaluated opportunities for energy efficiency, renewable energy, and 

transportation fuel reduction at Fort Carson. The analysis shows that Fort Carson has the 

potential to make significant progress toward becoming a net zero installation. If the base 

implements the recommended energy projects and savings measures, it would achieve a 92% site 

energy reduction and a 95% source energy reduction. By achieving this status, the base will set 

an example for other military installations, provide environmental benefits, reduce costs, increase 

energy security, and exceed its goals and mandates. 
105 

Appendix A. Electric Vehicle Grid Integration

Abstract...................................................................................................................... 106

Approach ................................................................................................................... 106

Model Assumptions............................................................................................................................ 107

Electrifying Fort Carson’s Fleet........................................................................................................... 107

Consumer Adoption of Electric Vehicles............................................................................................ 109

Fort Carson Electrical Loads ............................................................................................................... 113

Why Plug-ins? ........................................................................................................... 115

Electric Vehicle Infrastructure ................................................................................. 116

Charger – On-board/Off-board .......................................................................................................... 116

Cords and Connectors........................................................................................................................ 117

Electric Vehicle Supply Equipment..................................................................................................... 117

Grid Integration Scenarios ....................................................................................... 117

Scenario 1: Vehicle Charging (without management)........................................................................ 118

Scenario 2: Vehicle Charging (with management) ............................................................................. 118

Scenario 3: Vehicle Charging and Discharging (with management) .................................................. 124

Demonstrating EVGI at Fort Carson........................................................................ 132

Expected Issues ........................................................................................................ 134

Conclusions............................................................................................................... 135
106 

Abstract

Following the definition provided by the DoD/DOE Net Zero Analysis Task Force, a net-zero 

Fort Carson will require significant on-site energy generation and a high-efficiency fleet that can 

utilize on-site energy sources, among many other changes. As the availability and affordability 

of distributed renewable energy generation options will likely increase during the next decade, so 

will the plug-in vehicle options. NREL anticipates that Fort Carson will interact with plug-in 

vehicles belonging to the transportation motor pool as well as its military and civilian 

commuters. 

Specifically, the base’s alignment with the Army-funded demonstrations of all-electric trucks 

will ensure that a small number of electrified vehicles will soon reside on site. This report 

summarizes the potential costs and benefits of possible electric vehicle grid integration (EVGI) 

scenarios at Fort Carson. NREL has found that even at relatively small adoption rates, the control 

of electric vehicle charging at Fort Carson will aid in regulation of variable renewable generation 

loads and help stabilize the grid/microgrid. 

NREL recommends continued collaboration with Fort Carson to definitively understand the 

impacts of electric vehicles on the grid during both normal and microgrid operations. 

Approach

NREL investigated multiple applications of plug-in electric vehicles (PEVs) searching for 

feasible benefits in the form of petroleum reduction, renewables integration, and microgrid

stability. This analysis first considers the management of all-electric fleet vehicles. Analysts 

simulated the deployment of representative models of electric trucks available via GSA as 

substitutes for using vehicles in the Fort Carson Motor Pool. 

Next, NREL modeled commuter electric vehicles, based on performance and nationwide rollout 

plans for the Nissan Leaf and GM Volt.25 Light-duty PEVs are currently in production and 

scheduled to arrive at select dealerships and in national fleets in the fall of 2010. The model 

assumes that a small portion of the Fort Carson commuter fleet will plug in on-base. 

In the coming years, vehicles will for the first time utilize the electric grid. To assess the electric 

grid impacts of PEVs, NREL modeled Fort Carson’s electricity demand profile under both 

typical loads, and loads during critical operations (with a lower, more variable base load 

representative of emergency islanding as a microgrid). We analyzed three primary vehicle-grid 

interactions: 

• Full-power charging without management 

• Full-power charging capability, controlled by local grid authority 

• Full-power charge and discharge capability, controlled by local grid authority. 

Management of the PEV charging rates will allow the base to regulate and eventually optimize 

electrical loads for peak generator efficiency with high utilization rates for renewable energy. 

These simulations assume two-way communication between the grid operator and the vehicles 

 

25 Voiced by Nissan and GM executives and the DOE Plug-in Vehicle and Infrastructure Workshop, July 22, 2010. 
107 

(or a third-party aggregator). Grid and vehicle fleet will exchange information regarding how 

many vehicles are available as well as their batteries’ states of charge. 

Model Assumptions

Each vehicle in the model represents one of the 18,789 commuters who live off-base. We 

categorize these vehicles as either conventional, plug-in hybrid electric vehicle (PHEV), allelectric vehicle (AEV), or GSA fleet electric trucks. To simplify analysis, each PHEV, AEV, and 

electric truck sub-fleet described below in Table A-1 is categorized with generic characteristics 

representative of similar PEV options expected to be available in the market by late 2010. 

Table A-1. Modeled Vehicle Characteristics

Vehicle Type PHEV AEV

Electric 

Truck

Battery Capacity 12 25 80 kWh

Energy 

Consumption 300 250 800 Wh/mi

Charge-Depleting 

Range 40 100 100 mi

Life-Expectancy 15 15 15 years

EVSE Charge 

Level 2 2 3

Each vehicle operates independently in these simulations but also influences the net effects. This 

electric fleet—carrying multiple megawatt-hours of storage—creates an important dynamic 

resource for Fort Carson. 

Electrifying Fort Carson’s Fleet

The NEL assessment found that nearly one quarter of the 500-vehicle GSA-leased transportation 

motor pool (TMP) is currently well-suited for replacement with one of the three all-electric truck 

options now available via the GSA. Further projections of PEV mass market penetration vary 

widely, but for this study we assume a steady growth in electric truck acquisition based on a Bass 

technology diffusion curve26 and Energy Information Administration forecasts27 as Figure A-1

shows. 

 

26 Bass, Frank M. 1963. “A Dynamic Model of Market Share and Sales Behavior,” Frank M. Bass, Proceedings, 

Winter Conference American Marketing Association, Chicago, IL. 27 Bureau of Transportation Statistics, 

www.bts.gov/publications/state_transportation_statistics/state_transportation_statistics_2009/. Retrieved July 1, 

2010.
108 

Figure A-1. Assumed GSA vehicle adoption

The Directorate of Logistics and the Directorate of Public Works at Fort Carson indicated that 

transport shuttles, bucket trucks, stake trucks, and refrigerated vans all represent highly valuable 

roles of PEVs on base. Their mission of continuous, short trips during the day on-base, returning 

to the same lot each night, reflects the ideal electric vehicle duty cycle. Similarly utilized 

delivery vans and general use medium-duty trucks also present valid opportunities for electric 

drive. 

Figure A-2. The Smith Electric Newton all-electric truck, upfitted into one of many different 

configurable options (Credit: Smith Electric Vehicles, PIX 17631) 

Table A-2. Electric Truck Options Available on the 2010 GSA Schedule

GSA Vehicles Smith Newton Zero Truck ZT Enova Ze

GVWR Class 4 to 6 3 to 5 3 to 4

GSA Item Number 571E.1 95E 134E.1

Maximum Range (mi) 100 75 150

Maximum Speed (mph) 50 60 65

GSA Base Price $167,000 $142,100 $109,500 

Incremental Cost $109,548 $119,573 $80,309 

 

2012 2020 2030

0

0.2

0.4

0.6

0.8

1

GSA Motor Pool Mix at Fort Carson

year

fraction of vehicles

AEV

HEV

AFV

Diesel

ICE
109 

Each of these medium-duty commercial platforms has a large battery capacity (60-120 kWh) to 

meet typical daily driving distance requirements and at least one will have the opportunity to fast 

charge at rates of nearly 20 kW (see Table A-2). This will provide adequate mission capability 

for intra-base delivery, troop transportation, ambulance support, civilian shuttles, and other 

executive services. At current utility charges, fuel to drive each mile will cost less than $0.03, 

roughly 80% less than the gasoline that current TMP trucks and vans consume, as Figure A-3

shows.28 

Figure A-3. Vehicle technology operational cost comparison

Consumer Adoption of Electric Vehicles

In addition to GSA-leased electric vehicles, commuter electric vehicles will be soon available 

and in close competition with today’s conventional and hybrid options. After over two years of 

publicly affirmed dedication to commercially available all-electric and plug-in hybrid electric 

vehicles by automotive manufacturers, battery manufacturers, and the U.S. Department of 

Energy―the near-term certainty of public adoption is established. 

 

28 Estimate is based on Colorado Springs Utility rates, June 2010. Maintenance and acquisition costs are excluded.
110 

Figure A-4. Assumed vehicle adoption trends

The longer term adoption trend between today and 2030 is a matter of less certainty, but we may 

estimate it in a similar manner as that used for motor pool vehicle turnover, as Figure A-4 shows.

Vehicle life expectancy (in Table A-1) determines the time of retirement of each asset. We 

expect sales of AEVs to grow at a similar rate to PHEVs, but PHEVs occupy a larger market 

fraction because of their added range capabilities.

More than 30,000 people work at Fort Carson each week day and nearly all commute 

individually.29 This model considers the 18,289 that come in each day from off-base. We used a

database containing the zip codes of Fort Carson’s commuters to approximate travel distance 

(and thus the energy required to make that trip) for each (see Figure A-5). Our analysis assumed 

that each employee drove to Fort Carson in a single-occupancy vehicle from the center of their 

mailing address zip code.

 

29 Discussions with Fort Carson personnel.

2012 2020 2030

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Commuter Vehicle Mix at Fort Carson

year

fraction of vehicles

AEV

PHEV

HEV

AFV

Diesel

ICE

 
111 

Figure A-5. Starting locations for Fort Carson commuters

The analysis assigned each commuter a likelihood of driving an all-electric vehicle (AEV) or a 

plug-in hybrid electric vehicle (PHEV) based on market sales of these vehicles in the Colorado 

Springs region as well as on their commute distance relative to the vehicle maximum range. A 

safety factor of 2.2 times the commute distance was applied to this range-based-selection, so that 

even without a charge at work, each commuter could complete a round trip with 20% capacity to 

spare. 

The subject fleet in these analyses represents the 2030 PEV adoption rates, as Figure A-6

summarizes. Nearly 80% of the total commuter-miles traveled each day were in commutes 

within 40 miles. In the future, therefore, AEVs and PHEVs represent ideal choices, being 

capable of providing all-electric transportation for these distances.
112 

Figure A-6. Commuter distance from Fort Carson (top) and PEV mix (bottom)

NREL created energy storage resource allocation profiles by assuming the times during which 

vehicles were present at the base. We modeled the motor pool was modeled in similar fashion, 

although we assumed it to operate during the day and park at night and throughout weekends. 

We modeled the gradual phase-in of commuters (and commuter energy) as the motor pool (and 

motor pool energy) phased out during the morning as a function of a random distribution applied 

to arrival and departure times. The opposite trends occurred in the evening as commuters 

departed and motor pool vehicles returned. During weekdays the commuters in this model arrive 

at 8:00 am, plus or minus a standard deviation of 30 minutes, and leave 9 hours 30 minutes later, 

plus or minus 30 minutes standard deviation (not present on weekends). Figure A-7 summarizes 

these schedules and the energy storage potential in the 2030 PEVs. 

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All-Electric

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Other
113 

Figure A-7. Commuter and fleet vehicles avaiable at Fort Carson during weekdays

Fort Carson Electrical Loads

Sandia National Laboratory’s microgrid assessment defined the critical loads used in the 

emergency scenario simulations. We then interpolated these hourly average demands (peaking at 

4.3 MW) and scaled them to approximate the average demands during normal operations 

(peaking at over 25 MW).

Solar power production data is not yet available from Fort Carson; however, analysts took data 

from meters on NREL’s solar array and scaled them to 2 MW, representative of the current array 

size on-base. We then subtracted the resulting power from the demand load, to provide the net 

loads that the utility must generate.

Utility generation profiles during normal operations represented Colorado Springs Utilities’ fuel 

mix from 2009,30 scaled to the demand profile of the simulation time period (see Table A-3).

Table A-3. Colorado Spring Utilities' Fuel Mix, 2009

Resource

Capacity 

(MW)

Power 

(MW)

Energy 

(MWh)

Coal 462 42% 61%

Hydro 34 10% 27%

Natural Gas/Oil 115 46% 8%

Wind 0 0% 0%

DSM 0 2% 1%

Purchases 0 0% 3%

 

30 Colorado Spring Utilities’ Evaluation of Potential Options to Meet the CO2 Reduction Goals of the Colorado 

Climate Action Plan. www.csu.org/residential/environment/renewable/standard/item5137.pdf, June 1, 2009. 

Accessed July 22, 2009.

0000 0400 0800 1200 1600 2000 2400 0

5

10

15

20

number of vehicles (thousands)

hour of the day

Vehicles Parked at Fort Carson

0000 0400 0800 1200 1600 2000 2400 0

10

20

30

40

energy available (MWh)

Commuters

Motor Pool

Commuter Energy

Motor Pool Energy
114 

The final generation profile was an estimate that depicts how each rise or fall in demand can 

affect the fuel consumption and emissions of the electric grid. Colorado Spring Utilities 

consumes mostly coal to provide a stable base load. The utility also takes advantage of the 

natural water resources in the area to provide over one-quarter of their energy cleanly with 

hydro-power. Figure A-8 presents typical week. 

Figure A-8. Base load at Fort Carson with conventional and 

solar generation mix during normal operations

During emergency operations, NREL assumed that the base will run a series of diesel generators 

to meet the needs of mission critical loads, while still incorporating the same level of solar 

power. Any grid instabilities created by power fluctuations from on-site variable renewable 

generation will be magnified in a critical load scenario. Figure A-9 displays the emergency 

generation profile during the same week as in Figure A-8, presenting up to 25% load variance 

between peak and trough. Generators operate most efficiently in relatively narrow power bands; 

this diurnal ramping will increase total fuel needs as the generators move through these bands. 

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Fort Carson Base Load

Coal

Hydro

NG/Oil

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115 

Figure A-9. Emergency demand and generation profile

It is important to note that the load profiles used for these scenarios do not reflect actual loads at 

Fort Carson because that data was not recorded at the time of this analysis. Proper grid utilization 

of PEVs depends heavily on the proper matching of vehicle usage profiles, infrastructure, and 

grid activity.

Why Plug-ins?

Plug-in vehicles range from plug-in hybrid electric vehicles (PHEVs) of varying battery 

capacities (and all-electric ranges) to all-electric vehicles (AEVs, or EVs); both offer two 

potential benefits to the operator:

• High rates of petroleum consumption displacement (via enhanced efficiencies)31

• Clean and affordable operations (via fuel diversity from relatively inexpensive and 

potentially renewable sources).

32

These automotive technologies, when deployed appropriately with the proper control, can also 

facilitate the build-out and maintenance of a cleaner, more reliable grid. While parked—and the 

 

31 Markel, T.; Smith, K.; Pesaran, A. “Improving Petroleum Displacement Potential of PHEVs Using Enhanced 

Charging Scenarios” EVS24. 

32 Parks, K.; Denholm, P.; Markel, T. Costs and Emissions Associated with Plug-In Hybrid Electric Vehicle 

Charging in the Xcel Energy Colorado Service Territory. NREL/TP-640-41410. May 2007. 

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Diesel 1

Diesel 2

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Diesel 5

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Solar
116 

average car is parked more than 90% of the time33—plug-in cars will provide a flexible load or 

possible energy storage with adjustable charge and discharge capabilities. NREL found that if 

Fort Carson applies such grid stability options to its microgrid, the base may experience 

amplified savings and power quality benefits when compared with larger, more regional 

operations. 

Although they bear a high initial price, the financial benefits of electrified vehicles during 

operation may pay for incremental costs amortized throughout the period of vehicle ownership. 

For the purposes of this study, PEVs will represent the multiple electrified vehicle configurations, 

and PEV operations will consist of both transportation and smart grid integration (charging, 

discharging, communications, etc.). 

Electric Vehicle Infrastructure

An electric fleet will require the following infrastructure34 in the same way that a conventionallyfueled fleet will require maintenance equipment, storage accommodations, and fueling 

infrastructure. Though standardization is currently lacking, commercial options exist for each 

item:

Charger—On-board/Off-board

The power electronics for charging the energy storage system could be on-board or off-board the 

vehicle. Improving the efficiency and cost of this component may be critical to the success of 

electrified transportation. The weight of on-board units is also important. On-board units take 

AC power from the grid and rectify it to DC power in order to charge the DC battery pack. Offboard units make this same conversion and deliver DC power to the vehicle. There must be 

communication between the battery management system and the charger to ensure the safe 

delivery of energy. Power-quality standards for chargers are under development, with the goal of 

minimizing detriment al impacts to grid operation. 

Figure A-10. Illustration of PEV infrastructure (Credit: Dean Armstrong, NREL)

 

33 Markel, T.; Kuss, M.; Denholm, P. “Communication and Control of Electric Drive Vehicles Supporting 

Renewables.” IEEE Vehicle Power and Propulsion Systems Conference, September 2009. 34 The following descriptions are taken from Markel, T. “Plug-in Electric Vehicle Infrastructure: A Foundation for 

Electrified Transportation.” MIT Energy Initiative, April 8, 2010.
117 

Vehicle charging infrastructure also offers the opportunity to reverse power flow from the 

vehicle battery to the grid. Users must balance, however, the value of this scenario with its 

inefficiency and battery-life impacts.

Chargers and associated cords are categorized by voltage and power levels: Level I is 120V AC 

up to 20A (2.4kW), Level II is 240V AC up to 80A (19.2kW), and Level III (which is yet to be 

defined fully) will likely be 240V AC and greater at power levels of 20–250kW.35 It is expected 

that similar definitions will be created to categorize charging with DC power delivery. 

During these simulations, the commuter vehicles charge (and discharge) via Level II architecture 

(limited to 7.7 kW: 32 amps, 240 Volts). The electric fleet trucks use Level III (limited to 20 

kW: 50 amps, 400 Volts DC). 

Cords and Connectors

In the previous generation of EVs, cords and connectors became a point of debate and made 

introduction challenging. Today, SAE has led efforts for United States-wide standardization of 

connectors for conductive charging. The SAE J1772 standard defines a five-pin configuration 

that will be used for Level I and Level II charging.35 SAE is investigating the use of the J1772 

connector for DC power flow as well. Level III connectors are under development. Tripping 

hazards due to cords in garage areas and public places may be a safety and adoption hurdle. 

Electric Vehicle Supply Equipment

Electric vehicle supply equipment (EVSE) improves the safety of vehicle charging in accordance 

with the National Electric Code (NEC). The EVSE enables power flow between the electricity 

distribution system and the PEV only when a cord and connector are completely connected. For 

Level II charging, the cord is permanently attached to the EVSE and is de-energized when not 

connected to the vehicle inlet. The EVSE and charger may be a single component if the charger 

is located off-board the vehicle. In some regions, the EVSE will be attached to or include a submeter for measuring electricity delivered to the vehicle separate from electricity delivered to the 

rest of the premise. This feature supports low-carbon fuel standard accounting. 

The installation of an EVSE in a building may present a significant hurdle to adoption because it 

involves multiple parties, including utilities, building inspectors, electricians, and vendors.36 The 

time from purchase to functioning installation might be as much as 30 days in some regions 

providing a less than ideal experience for consumers. A discussion of related codes and standards 

efforts follows. 

Grid Integration Scenarios

The Fort Carson EVGI forecast yielded a fleet of 908 AEVs, 1,362 PHEVs, and 75 electric 

motor pool trucks in 2030. These vehicles occupied parking spaces in this simulation during the 

same assumed times as the internal combustion engine (ICE) vehicles they replaced. When 

plugged in to EVSE at these parking spaces, vehicles charged or discharged based on a series of 

algorithms and limits framed in three scenarios. 

 

35 “SAE Electric Vehicle and Plug in Hybrid Electric Vehicle Conductive Coupler.” SAE J1772. January 2010. 36 “Electric Vehicle Charging Infrastructure Deployment Guidelines British Columbia.” BC Hydro. July 2009.
118 

NREL chose these scenarios to capture the most likely range of grid-integration effects: 1)those 

that require little or no work with the highest risks (vehicle charging without management), 2) 

those that require some work with the least risk (vehicle charging with management), and 3) 

those with the greatest benefits and the greatest costs (vehicle charging and discharging with 

management). 

Scenario 1: Vehicle Charging (without management)

Also known as opportunity charging,

31 unmanaged charging began in these simulations at the 

maximum rate as soon as the vehicle was parked and plugged in. At Fort Carson, opportunity 

charging coincided with demand peaks, creating wildly high electricity loads [and costs] as 

Figure A-11 shows. Each large spike in the morning adds more than 7 MW to the base load. 

Vehicle charge energy totals 11 MWh each day.

Figure A-11. Opportunity charging at Fort Carson during normal operations

Next, we analyzed a critical-load scenario within an islanded Fort Carson, when only GSA 

electric trucks are plugged in and 50% of them still operate during the weekdays. Unmanaged 

charging results in 800 kW additional loads totaling 1.4 MWh each day, as Figure A-12 shows. 

Figure A-12. Opportunity charging during emergency microgrid operations 

Scenario 2: Vehicle Charging (with management)

Today, regional utilities employ demand response programs to reduce excess costs during 

peaking demands by curtailing certain customer equipment under specific agreements in 

Sun Mon Tue Wed Thu Fri Sat

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power load (MW)

Fort Carson Base Load with Electric Vehicle Charging

Net Load w/PEVs

Base Load

 

 

 

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Fort Carson Base Load with Electric Vehicle Charging

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Base Load

 

 

 
119 

exchange for payment to the customer. In a similar fashion, controlled charging of vehicles is 

another load that grid operators can regulate to counter any large demand or supply transients, 

which could damage equipment or even cause blackouts. 

Under the NZEI initiative, Fort Carson may add renewable energy generation to the 2 MW of 

solar photovoltaic arrays already on-base. Compared with fossil fuel generators, renewable 

supplies can vary widely with unexpected changes in the weather. Increasing the utilization rate 

of renewable generation while reliably meeting the demand requires a buffer, which is a role that 

parked (and plugged in) PEVs may play well.

The electric fleet could smooth many of the power drops during periods where large numbers of 

commuters were parked on base by regulating charging. However, as Figure A-13 shows, many 

quick changes of 20% or more of the peak demand still occurred within only a few hours and 

without compensation. These fluctuations may create significantly more costs for the utility than 

the savings resulting from smoothing with PEV charging. 

Figure A-13. During normal operations, both commuters and motor pool charging smoothes the 

required ramp rates for conventional generation

Although the benefits to the grid are relatively small, the vehicles received adequate charging 

without exceeding peak demand and at times even reduced peaks when solar power was 

available. Commuters left the base in these simulations with 60-100% of their capacity while 

providing a grid smoothing service; fleet trucks were 100% recharged before each day’s route. 

Figure A-14 shows the remaining range left in the vehicles’ batteries at any given time relative to 

a usable capacity (~80% of total). Each line represents a unique vehicle. Commuter vehicles are 

charged during the day while motor pool vehicles are charged at night, though neither uses more 

than 50% of their range capability (because of the selection process described earlier in a section 

headed “Consumer Adoption of Electric Vehicles.” 

 

 

 

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power load (MW)

Fort Carson Base Load with Electric Vehicle Charging

Net Load w/PEVs

Base Load
120 

Figure A-14. Charging at ideal times supplies plenty of range for return commutes

On the other side of the meter, the fluctuations in power demand were smoothed when energy 

was available. When large amounts of solar energy became available (which frequently occurs as 

the sun emerges from cloud cover), PEVs absorbed the additional unexpected energy at a 

moment’s notice (see Figure A-15). In practice, this compensating reaction would allow 

additional time to efficiently ramp down large generators without causing dangerous swings in 

voltage or frequency on the grid. The peaking plants that provided PEV charge energy in these 

simulations—natural gas turbines—typically produce cleaner power than coal, especially while 

functioning efficiently without severe changes to their power levels. 

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Plug-in Hybrids

battery capacity remaining (miles)

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GSA Fleet

battery capacity remaining (miles)
121 

Figure A-15. Controlled charging helps to slow the drop-offs in demand during normal operations

Integrating vehicle charging made the net generator profile slightly more predictable 

(Figure A-16).

Sun Mon Tue Wed Thu Fri Sat 11

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Coal

Coal w/PEVs

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Hydro w/PEVs

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Generator Loads for the Entire Base

NG/Oil

NG/Oil w/PEVs
122 

Figure A-16. Charging smoothes the aggregated load profile during normal operations

The results in Figure A-17 show that during emergency operations, properly managed charging 

deferred the vehicle power requirement to times when the demand is lower or when excess 

renewable energy was available. Each evening a large portion of the load reduction was absorbed 

by charging the motor pool electric trucks. Unfortunately, in this scenario, the 50% of vehicles 

that remain parked became relatively useless once completely charged. The benefits after these 

times were relatively diminished in the simulation. 

Figure A-17. Charge management can help buffer steep power fluctuations 

during emergency operations

Even with these charging restrictions, the Fort Carson microgrid could still provide enough 

energy for these vehicles each day without creating a new peak in demand. Figure A-18 shows 

the range capability for each electric truck. Each line represents a single truck’s charge profile 

(or multiple trucks with identical charge profiles) while parked. 

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Net Load w/PEVs

 

 

 

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Fort Carson Base Load with Electric Vehicle Charging

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123 

Figure A-18. Charging at ideal times supplies full range for all electric trucks 

during emergency operations

In fact, diesel fuel could be used more efficiently in on-site transportation by running generators 

that charge electric trucks during emergency conditions rather than by fueling diesel-powered 

trucks. Large generators run at roughly 35% efficiency and charge the vehicles at about 95% 

efficiency. Electric power trains in these vehicles operate at an average of about 80-85% 

efficiency, totaling roughly 27% pump-to-wheels efficiency while the average diesel truck runs 

at closer to 20% efficiency on average. Fort Carson’s fleet can drive nearly 35% further with 

each gallon of fuel in electric vehicles and still support the microgrid. 

This scenario affected generators significantly less than during normal operations. The change in 

operating profiles of the top most affected generators (in Figure A-19) show that the fleet alone 

adds relatively minimal loads and is unable to significantly level any major fluctuations. 

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Miles Remaining for Each Vehicle Analyzed

time of day

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battery capacity remaining (miles)
124 

Figure A-19. Generators receive little benefit from an electric truck fleet 

during emergency operations

Scenario 3: Vehicle Charging and Discharging (with management) 

The ability to discharge PEVs effectively doubles the range of power with which a grid operator 

can regulate the systems power budget. Additionally, the storage capacity of the PEVs connected 

to the grid could be used in load shifting and long duration load leveling. 

Compared with the model results during charge management, the resulting net load profile with 

vehicle discharge capability was significantly smoother. Any sharp changes in load occurred 

primarily during times that vehicles left the charging station (to go home or on a route) as Figure 

A-20 shows. Those times coincided with large changes in the assumed demand loads. 

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Diesel 6

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125 

Figure A-20. V2G enabled load optimization and peak shaving during normal grid operations 

This additional flexibility provided an opportunity to utilize generation resources in an optimal 

combination based on price, emissions, or other metrics. The actual source providing generation 

for PEV charging was selected for this simulation in the order in which it was deployed (base 

load, then peaking plants, then renewables). Figure A-21 depicts vehicle charging as positive 

power; discharging is negative. The different colored areas beneath the total load shift curve 

indicate the source of power generation or offset resulting from this scenario. 

Figure A-21. Charging utilizes primarily solar power while V2G offsets fossil fuels

 

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Fort Carson Base Load with Electric Vehicle Charging

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Generation Supply to [and Generation Offset by] PEVs

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Net Load Shift
126 

Providing power back to the grid, the multiple commuter PEVs still left each day of the 

simulation with plenty of range to return home. The motor pool vehicles, due to their high power 

capabilities (Level III) and small quantities, exhibited wide capacity swings. Results in Figure A22 demonstrate the usefulness of each.

Figure A-22. With V2G each commuter exchanges relatively little energy while fleet vehicles 

manage nighttime and weekend loads

The final generator loads showed a delay in hydro power demands (giving additional warning for 

changes to their operating points) and a much smoother peaker plant profile. As shown in Figure 

A-23, the fleet shaved the highest peak, on Tuesday, by nearly 25%. 

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127 

Figure A-23. V2G shaved peaks and fills valleys in the generator load profiles 

during normal operations

By integrating PEV energy storage, the normal Fort Carson demand profile, originally a spiky, 

unpredictable mess, ended up with almost two distinct power setting, quite predictable. 

Unfortunately, each day’s resulting load contained large step changes from vehicles leaving and 

entering the grid (see Figure A-24). This pattern must be managed with alternative scheduling, or 

community energy storage devices. 

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128 

Figure A-24. Comparison of generation with and without PEVs exhibits their effect 

and potential benefits

During emergency operations, even a small fleet of electric trucks can help prevent some 

extreme load swings and better utilize the solar energy on-base. Mid-day loads during 

Wednesday and Thursday presented the highest concern, as they dropped significantly when 

demand was usually the highest. Additional solar power exacerbated the problem. As stated 

earlier, these profiles likely did not closely reflect actual loads on base. Figure A-25 shows the 

results of the exercise. 

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129 

Figure A-25. Microgrid management of electric fleet truck V2G helps stabilize unpredictability 

of load demands and renewables supply

The supply to PEVs in Figure A-26 came primarily from solar power, enabling either clean 

transport, renewable load shifting, or both. Conversely, the power displaced by PEVs came

primarily from the first three diesel generators. 

Figure A-26. Electric vehicles can help maintain emergency generators 

at optimal operating conditions 

These grid management services require significant use of the fleet truck batteries, but the 

diurnal fluctuation in loads only draws approximately the equivalent of one cycle per day on 

each (see Figure A-27).

 

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Fort Carson Base Load with Electric Vehicle Charging

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Generation Supply to [and Generation Offset by] PEVs

Diesel 1

Diesel 2

Diesel 3

Diesel 4

Diesel 5

Diesel 6

Solar

Net Load Shift
130 

Figure A-27 exhibits the even wider, more sporadic variations in state of charge that the motor 

pool experienced in these simulations. 

Figure A-27. Battery state of charge fluctuations during emergency V2G cycle 

roughly once per day

With relatively continuous storage assets, the microgrid in this simulation had large buffers 

which helped to delay and drastic changes. Again the top three generators handled the majority 

of load fluctuations; Figure A-28 shows their reactions. 

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Miles Remaining for Each Vehicle Analyzed

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battery capacity remaining (miles)
131 

Figure A-28. V2G extended delay time and reduced overall ramping of generators 

during emergency operations

The net effects of these 75 fleet vehicles charging and discharging were easily recognizable 

when compared with a microgrid lacking any vehicle support (see Figure A-29).

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Diesel 6

Diesel 6 w/PEVs
132 

Figure A-29. Even a small fleet of motor pool PEVs enabled gradual ramping of loads during 

emergency operations when compared with the baseline scenario

Demonstrating EVGI at Fort Carson

In the future, Fort Carson is expected to become one of several focal points for a Joint 

Commands Technology Development (JCTD) project referred to as SPIDERS, with PACOM 

and USNORTHCOM orchestrating multi-force collaboration to expand deployment of secure 

microgrid technology. Creating technology with an acceptable readiness level is critical in 

support of the JCTD. One critical technology deployment will be vehicle-to-grid (V2G) 

technology providing stability management of microgrids with large scale renewables. The 

power flow management technology, the communications infrastructure, and systems operation 

scenarios are yet to be defined. The work outlined in the sections that follow, if conducted during 

FY 2011 would create the knowledge necessary to fill the gap between technology development 

and deployment in support of the V2G technology needed for SPIDERS. 

NREL internally funded work during the past two years and in the coming year that provides a 

foundation of research on vehicle-to-grid technologies, testing, and operations. A pilot 

Renewable Charging Station and a demonstration PHEV with V2G has been created. V2Gcapable vehicles have been tested to existing grid integration standards. A bi-directional Level III 

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power load (MW)

Fort Carson Base Load

Diesel 1

Diesel 2

Diesel 3

Diesel 4

Diesel 5

Diesel 6

Solar

Sun Mon Tue Wed Thu Fri Sat

0

0.5

1

1.5

2

2.5

3

3.5

4

day of week

power load (MW)

Net Load for the Entire Base with PEVs

Diesel 1

Diesel 2

Diesel 3

Diesel 4

Diesel 5

Diesel 6

Solar

Net
133 

fast-charge system is planned for installation at NREL in FY 2011 Q1. This system will offer a 

facility for understanding the attributes and grid impacts of fast-charge systems.

Figure A-30 depicts the combination of PV providing shade for vehicles and energy to the 

microgrid along with vehicle energy management portals. The portals show a combination of 

Level III (20–250KW) and Level II (0-20kW) access points (as indicated). Systems optimization 

analysis is needed to understand the scalability to satisfy several vehicles to thousands of 

vehicles. We recommend further investigation to determine the attributes of this system relative 

to available electricity grid distribution systems and the microgrid operations. 

Figure A-30. Scalable renewable PEV energy management component for microgrids 

(Credit: Mike Simpson, NREL)

With the added benefits of providing premium covered parking, these systems will add to the onsite renewable energy generation without occupying rooftops. NREL’s NZEI team identified 

several locations along the microgrid corridor in which these carport-charging systems may be 

particularly valuable (see Figure A-31). 
134 

Figure A-31. Possible solar carport locations

Expected Issues

While this model represents relatively high-fidelity estimations of potential electric vehicle grid 

interactions, we can solidify the details required for implementation planning only through 

demonstrations as just described. We will have to address several remaining deployment 

considerations in this next phase. Issues include: 

• Capital and installation costs of EVSE. Many EVSE manufacturers have published 

MSRPs for their various products, but great uncertainties in the costs of permitting 

and installation contracts remain. These factors will vary significantly depending on 

the municipality and contractor. 

• Circuit supply upgrade requirements. Building codes are quite different between 

locations. Electrical infrastructure “behind the wall” of EVSE locations may require 

as little as no development, or as much as total rework, depending on the age and 

location of a facility and power availability (phases, voltages, amperage). 

• Dedicated parking spots. Consumer studies indicate that PEV owners/operators will 

want to charge their vehicles often37 and EVSE may be in high demand at Fort 

 

37 Neenan, B.; Cromie, R.; Wheat, T. “Characterizing Consumers’ Interest in and Infrastructure Expectations for 

Electric Vehicles: Research Design and Survey Result.” EPRI. May 2010.
135 

Carson. The need for EVSE may or may not align with the desire for dedicated 

parking and the needs of the microgrid. 

• Electricity accounting differences between civilian and military vehicles. If we 

view commuter vehicles as a resource to the base’s grid operations, they must be 

provided with electricity. The rates at which charges are made available to civilian 

owners of these vehicles will be at the administration’s discretion and will likely be 

different than the rates for GSA vehicles. Additionally, a non-utility is restricted from 

reselling electricity, but can recoup expenses by establishing fees for parking or time 

at the charger.

• Fleet vehicle turnover rates with respect to payback period of grid services. GSA 

vehicles are typically replaced within a few years (and only heavy duty vehicles are 

kept for longer than 10 years),38 but some of the first waves of PEVs will have 

incremental costs that require longer payback periods based on fuel savings alone. 

Fortunately, battery price forecasts indicate incremental costs will quickly drop, 

although the business case will depend on alternative functions (such as grid 

integration) early on.

• Feasibility and safety of bi-directional power flow in practice. Today, power is 

predominantly delivered to the grid by utility-sanctioned generators and distributed 

renewables (residential wind and solar), but requires sophisticated synchronization 

via highly refined power electronics. NREL tests indicate that bi-directional power 

exchange from vehicles (V2G) is feasible, but wide-scale implementation has yet to 

be demonstrated. 

• Secure data collection, handling, and communication. PEV grid integration can 

boost military security by enhancing the reliability of their grid. However, large 

amount of information will be exchanged in the “smart” microgrid, which enables 

these abilities and must be transmitted, processed, and stored securely. Precedents 

have been established, but with new equipment (or new uses of established 

equipment) comes new risk. 

• Relocation of staff (and their vehicles) with limited fixed EVSE. NREL has found 

that, due to the frequency with which offices are relocated within Fort Carson, 

dedicated parking is not worth a significant investment. EVSE is not typically 

relocated once installed, so it is important to properly plan and locate charging 

stations from the beginning of deployment. 

Conclusions

PEVs present opportunities to reduce fuel costs and utility bills, while meeting alternative fuel 

requirements. Their dual roles in efficient transportation and utility assets bolster a reduction in 

petroleum consumption and an increase in local fuel sources, especially renewable energy.

NREL found that Fort Carson can effectively use these vehicles in many, if not all, vehicle 

charge control scenarios to achieve internal and Federal goals, resulting in a more robust 

transportation and electricity system. However, these results are highly dependent on the 

 

38 GSA, “Important Fleet Publications.” www.gsa.gov/portal/content/104230. Accessed August 3, 2010. 
136 

assumptions, of which the demand load is the most questionable. Any further progress will 

require proper data collection from utility meters on base. 

Most notably, the PEVs exhibited the largest potential for enhanced grid efficiency when utilized 

in proper coordination, and/or with bi-directional charge capability. It was found that 75 motor 

pool vehicles did not provide enough benefit for justified investment in electric trucks in a 

controlled-charge-only configuration on the microgrid, but V2G changed the story significantly 

by effectively supplying storage with twice the power and energy ranges. 

True, in both normal and emergency situations, the relatively continuous storage assets assisted 

the microgrid in this simulation, providing large buffers and delaying drastic changes. With 

dedicated planning and software development, this reaction could help bolster the reliability of 

controls in the microgrid system. Still, arrival and departure times of vehicles coincided with 

large changes in the assumed demand loads. If the actual base loads turn out in reality to be

similar, it may become necessary to institute staggered schedules for additional grid stability. 

Finally, the small amount of control applied to charging dynamics in these simulations limits the 

minimum battery state-of-charge to each vehicle’s required commute/route energy, plus a 20% 

margin while providing this service. Generally, simulations did not reach this limit, but future 

control algorithms may utilize advanced regulation schemes. The wide swings in battery capacity 

reflect equally great benefits to the grid (representing power and energy offsets in generation), 

but cycling these batteries may have degraded them faster and replacement costs could 

eventually overshadow any energy savings. 

Regardless, this simulation study offers valuable insight to potential design spaces for a base 

with PEVs. The assumptions must now be vetted through an on-site, physical demonstration. 

NREL recommends that Fort Carson implement a program to demonstrate each of these modes 

of operation throughout 2011, as Smith Electric trucks and a microgrid infrastructure become 

available.
DOE/GO-10211-3329 ▪ October 2011

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least 50% wastepaper, including 10% post-consumer waste.