Bringing you a prosperous 

future where energy is 

clean, abundant, reliable, 

and affordable

Leading by example, 

saving energy and 

taxpayer dollars 

in federal facilities

DOE/EE-0308

Internet: www.eere.energy.gov/femp/

No portion of this publication may be altered in any form without 

prior written consent from the U.S. Department of Energy, Energy 

Effi ciency and Renewable Energy, and the authoring national laboratory.

Current Applications and Research 

in Photovoltaic Technology for Buildings

Th ree case studies illustrate diff erent benefi ts

Th e federal sector continues to be a leader in the implementation and demonstration of photovoltaic 

(PV) technology. Installing PV systems helps meet the goals of Executive Order (EO) 13123, which 

encourages each federal agency to “expand the use of renewable energy within its facilities and in its 

activities by implementing renewable energy projects and by purchasing electricity from renewable 

energy sources.” PV systems, like those presented in this report, help meet the goal of the Million Solar 

Roofs Initiative for the federal government to install 20,000 solar energy systems at federal facilities by 

2010. Installing PV systems can also help reach the government’s renewable energy goal—to have the 

equivalent of 2.5% of federal facilities’ electricity consumption supplied from new renewable energy 

sources by 2005.

Although most cost-eff ective PV installations in the past have been 

for remote, off -grid power applications, current installations include 

a variety of high-value grid-connected applications that provide 

reliable power, lower energy consumption and costs, and reduce 

harmful emissions. It may be more diffi cult for grid-connected 

projects to meet traditional cost-eff ectiveness criteria (e.g., brief 

payback periods) if only energy cost savings are considered. However, economics is not the single factor, and not always the most 

important factor, in determining whether to implement alternative, 

renewable energy systems such as PV.

Besides reducing energy costs, PV may provide benefi ts such as 

reducing harmful emissions from power plants, reducing peak 

demands for the facility and on the electrical grid, enhancing 

energy security, as well as, aiding the development of renewable 

sources of energy. Agencies that can place a dollar value on benefi ts such as those will be better able 

to justify installing these systems on the basis of cost.

Technology Description

PV technology converts radiant light energy (photons) to electricity (voltage). PV cells (also called solar 

cells) are the basic building blocks of this energy technology. PV cells are made of semiconducting materials similar to those used in computer chips. Single-crystal silicon is the semiconductor material most 

commonly used. Polycrystalline silicon, in the form of a thin fi lm or coating on an inexpensive base of 

glass or plastic, is also used, as well as thin fi lms of amorphous (noncrystalline) silicon. Although the 

cells are typically less effi cient than the crystalline silicon technologies, the amorphous silicon cells 

are usually less expensive to manufacture because they require less silicon and the process is simpler. 

Combinations of other materials, such as cadmium, copper, indium, gallium, selenium, and tellurium, 

are also used to manufacture PV devices. Sunlight is the most common source of radiant energy used 

by PV cells to produce an electric current.

Photovoltaic device.

M75-B171303
2 — FEDERAL ENERGY MANAGEMENT PROGRAM

Th e amount of electricity a PV cell 

produces depends on its size, its conversion effi ciency, and the intensity of 

its light source. PV cells often power 

calculators and watches, but they also 

supply electricity for much larger loads, 

such as residences and commercial 

buildings. For those loads, cells are 

connected together to form larger units 

called panels (or modules). Panels, in 

turn, are connected to form arrays, and 

arrays can be interconnected to generate electricity for still larger loads, such 

as a group of buildings. A PV energy 

system usually includes at least a panel 

or an array and the structural hardware 

needed to install it. Depending on the 

specifi c nature of the load, a PV system 

may also include

• Batteries to store electricity for use 

when the sun is not shining

• Battery-charge controllers to protect 

the battery by preventing overcharge 

and over-discharge

• Inverters to convert direct current 

(dc) electricity to alternating current (ac) electricity

• Converters to convert PV system 

voltage to a higher or lower voltage

• Solar trackers to optimize the solar 

gain of the PV array by tracking 

the sun

• Engine generators (for hybrid systems) to provide backup power and 

power for charging batteries.

Panels are typically installed on or near 

a building or other structure, such as 

covered parking. Th ey can also be specially designed as an integral part of a 

building’s roof, wall, skylight, or other 

element as building-integrated PV. 

Roof-mounted panels can be either 

off set-mounted above the roof or laminated directly to the roof membrane.

Th e dc electricity generated by a PV system must be inverted to ac electricity 

for use in typical commercial applications. PV systems can be either off -

grid (not connected to a utility grid) 

or grid-connected. (Th e applications 

discussed in this technology focus 

are all ac applications and all gridconnected.) Off -grid systems must 

include some type of energy storage 

or backup power source to supply 

power when the sun is not shining. 

For grid-connected systems, the utility grid serves as a backup.

As noted in case study 1, the following 

design elements are key to the successful installation of any PV system:

• Quality wire and conduit with no 

exposed wiring or wire connections

• Appropriate thermal management 

design of the solar array and the 

inverters

• Appropriate panel tilt and orientation to enhance sunlight capture 

and to mitigate soiling eff ects

• Correct fusing, switching, and other 

safety considerations

• A system design that incorporates 

functionality and serviceability

• Appropriate attachment details and 

assembly procedures

• Professional workmanship and use 

of proper tools

• Comprehensive system inspection, 

testing, and commissioning

• Experienced program management 

and project oversight

Benefi ts

Benefi ts of installing PV systems at 

federal facilities include these:

• Reliability—they operate for long 

periods with little maintenance.

• Low operating costs—the fuel is 

free, and there are few, if any, 

moving parts.

• Low environmental impact—they 

are quiet and nonpolluting (no 

greenhouse gas emissions) and 

require no air permitting.

• Standalone capability—they can 

operate in remote areas far from 

power lines.

• Modularity—power output can be 

increased by adding more panels.

• Safety—they are not fl ammable 

and meet National Electric Code 

requirements.

• Versatility—they operate well in 

almost any climate.

• Ease of installation—no heavy construction equipment is required.

• Grid support—they provide energy 

security in areas where electricity 

shortages are anticipated.

In addition, as discussed in case study 3, 

off set-mounted rooftop PV systems 

shade their roofs and so may reduce 

solar heat gain and the extra cooling 

that it makes necessary. At facilities 

where energy requirements are increasing, installing PV to handle the growth 

in demand may be less costly than 

expanding existing electric distribution equipment. PV systems can also 

provide grid support in areas where 

electricity blackouts are possible or 

shortages are expected. In most of the 

country, peak electrical demand occurs 

during the sunniest times of the day, 

which is when PV energy production 

is at its peak. PV can be used to off set 

demand during those hours, reducing 

the stress on the grid and avoiding extra 

cost for power purchased during peak 

demand periods.

PV systems can be highly cost-eff ective 

in off -grid applications because the 

cost of extending utility lines can easily 

exceed $10,000 per mile for fl at areas 

where lines are strung on poles. In the 

mountains, taking lines through the 

rough terrain can easily cost $40,000 

to $60,000 per mile. Many places 

require buried lines, and if rock is 

present, the cost of laying lines can 

soar. PV systems are already used in 

many of the government’s off -grid 

applications, such as emergency call 

boxes near interstate highways.

Grid-connected applications have the 

advantage of not requiring the use of 

expensive battery storage or backup 

power systems, because the utility 

grid acts as the backup power source. 

Often, grid-connected systems are 
FEDERAL ENERGY MANAGEMENT PROGRAM — 3 

sized to provide only a portion of 

the facility’s overall load, further 

reducing capital cost. It is more diffi -

cult to make systems cost-eff ective in 

grid-connected applications, where 

PV systems often compete with inexpensive utility-supplied electricity 

especially for federal facilities.

PV systems can easily be procured by 

federal agencies via General Services 

Administration supply schedules that 

cover most major makes of PV system 

components as well as complete systems. 

In addition, many electric utility companies that off er PV service programs 

will provide PV systems. Still, capital 

cost remains a major challenge to widespread implementation. Although the 

cost of PV panels has dropped from 

more than $100 per watt in the mid1970s to less than $6 per watt today, 

making use of rebate programs and 

identifying the ancillary benefi ts that 

PV systems can off er is crucial to fi nding cost-eff ective applications. Some 

ways of improving the economics of 

PV systems include

• Recognize and value the ancillary 

benefi ts of PV installations, such 

as reduced emissions or more reliable power

• Integrate PV into the building itself—

for example, installing a PV system 

during a regular roof replacement 

or considering a PV carport when 

new covered parking is needed so 

building material costs are off set

• Obtain rebates for PV systems (available only in some parts of the country) 

to reduce the capital costs

• Use federal fi nancing mechanisms 

such as energy savings performance 

contracts to reduce the initial cost 

of grid-connected PV systems

Besides being the smart thing to do in 

any facility, integrating energy effi ciency 

into a facility before installing PV also 

helps to reduce capital costs, because 

lower building energy consumption 

requires a smaller PV array and therefore less capital expenditure. As system 

costs continue to decrease and utility 

costs increase, PV should become more 

cost-eff ective.

Case Studies

Th e case studies discussed in this report 

highlight some recent federal PV installations: a grid-connected PV power system 

for mission-critical National Weather 

Service radar sites; a roof-mounted, gridconnected PV system for the U.S. Postal 

Service; and a roof- and wall-mounted, 

grid-connected PV system that quantifi es the benefi ts such systems provide in 

reducing building cooling loads. Th ese 

projects represent the current evolution 

of PV systems, as well as ways PV might 

be used in the future. Th e information 

provided in the case studies can be used 

to help facility managers determine if 

PV is right for a particular facility.

Case Study 1: Grid-Connected, 10-kW Solar PV System at a National 

Weather Service Facility

Overview

Th e U.S. Department of Commerce, 

the National Oceanic and Atmospheric 

Administration (NOAA), and the 

National Weather Service (NWS) 

requested technical assistance from 

FEMP in designing a 10-kW PV system 

for the NEXRAD (NEXt-generation 

RADar) system at NWS Miramar in 

California. NWS hopes to have PV 

systems installed at each of its nearly 

150 NEXRAD sites in the coming years. 

PV systems off er reliable power with 

no emissions and can help in meeting 

federal energy reduction and renewable 

energy implementation goals.

Th e pilot project at NWS Miramar 

consisted of designing and installing 

a PV system for demonstration and 

evaluation. Based on the pilot system’s performance, NWS plans to 

install additional PV systems at other 

NEXRAD sites. Th e system design 

developed in this project will serve as 

a standard design for the remaining 

installations, thereby capitalizing on 

the lower cost associated with a repeat 

design installation. During fi scal year 

2001, FEMP distributed a Technical 

Assistance Call for Projects, and NOAA 

was selected to receive funding. FEMP 

provided technical assistance using the 

National Renewable Energy Laboratory 

(NREL) to support the project. Subsequently, NREL worked with NOAA 

and the Bonneville Power Administration (BPA) to determine the optimum 

system size and how best to contract the 

design and installation. BPA continues 

to monitor the system performance.

Background

NWS has more than 150 nearly identical 

NEXRAD installations throughout the 

United States and overseas. NEXRAD 

is used to warn the public about dangerous weather and its location, using 

Doppler radar technology. Th e distinguishing feature of these radar sites is 

a 30-foot-diameter ball on top of a 

100-foot-high platform, as shown in 

Figure 1. Th e typical radar station uses 

around 180,000 kWh of electricity per 

year with a peak load of approximately 

30 kW. A large revolving radar dish and 

necessary computer equipment make up 

the load, as well as cooling needed to keep 

the high-tech equipment within its allowable operating temperatures. Currently, 

all systems are grid-connected, and each 

uses an uninterruptible power supply 

(UPS) and backup generator set for continuous power during grid outages.

Why install PV at all if these sites are 

currently grid-connected? Th ere are 

several advantages.
4 — FEDERAL ENERGY MANAGEMENT PROGRAM

• Overall electricity consumption and 

costs are reduced. Also, the long 

operating life of PV systems means 

the energy and cost savings can be 

expected for 20 years or more with 

low maintenance requirements.

• Emissions from fossil fuel consumption are reduced, including smogforming nitrogen oxides, CO2, and 

acid-rain-forming sulfur oxides.

• PV systems can off set new energy 

needs at a facility, avoiding costly 

expansions to existing electric distribution equipment. Grid-connected 

PV systems can also provide grid 

support in areas of the country 

where electricity blackouts are 

possible or shortages are expected.

• Because the electric grid acts as 

the backup power source in gridconnected PV installations, the 

costs of battery installation, 

maintenance, and repair can 

be avoided completely.

• In most parts of the country, peak 

electrical demand occurs during 

the sunniest times of the day, 

which is when PV energy production is at its peak.

Th e Miramar NEXRAD site receives 

electricity from the local utility, San 

Diego Gas and Electric. To operate 

through power outages, the facility 

with the installation and commissioning procedures, is standardized.

PV System Description

Th e fi rst step in developing a PV system 

design for NWS Miramar was to determine the appropriate system size. Th e 

essential elements that drive the size of 

any PV system are

• available real estate or roof space for 

placing the solar array

• annual energy use by the site and 

estimated energy delivery by the 

PV system

• budget and net turnkey price

• cost of electrical energy to the facility

Mounting the system on the roof spaces 

of the existing outbuildings was considered but dismissed. Such an installation 

was not optimally oriented for solar 

exposure and would have subjected 

the PV array to shading from the radar 

tower. Th e available land at the Miramar site was limited by the sloping hill 

on the south side of the fenced facility. 

Fortunately, the natural tilt of the slope 

and its perfect size to accept 10 kW of 

PV were well suited to this fi rst of potentially many repeatable installations.

Analysis showed that a PV system sized 

at approximately 110 kW could supply 

100% of the annual energy used by the 

facility, but it would have required more 

land than was available. Th e 10-kW 

system will supply approximately 9% 

of the facility’s yearly electrical needs. 

Th is smaller-scale installation has a 

manageable cost and allows NWS 

staff to familiarize themselves with the 

system’s operation and determine if 

broader implementation is warranted.

Th e 10-kW PV array consists of four 

relatively large panels sized approximately 4.7 x 28 ft. Each panel comprises 

24 Kyocera KC 120-1 solar panels wired 

in series to yield approximately 2.5 kW 

per panel. Th e four panels, or subcircuits, are combined in parallel to 

form one 10-kW array feeding into 

a 10-kW inverter, Trace Technology 

has a UPS system housed in an airconditioned building and a backup 

diesel generator in another building. 

A transfer switch connects the UPS 

to the utility when the utility is up 

and running or to the generator when 

the utility goes down. Th e radar dome 

and buildings are fenced inside a 60 x 

90-foot area with open space surrounding the perimeter. Th e design goal for 

this project was to have a robust system 

design that required virtually no maintenance and did not interfere with the 

site’s primary mission—all at the lowest 

cost possible. Furthermore, the system 

design had to be replicable for future 

installations in a variety of geographic 

locations. Th e following design elements 

helped to achieve these goals and are critical to the successful installation of any 

PV system:

• Quality wire and conduit with no 

exposed wiring or wire connections

• Appropriate thermal management 

design of the solar array and the 

inverters

• Appropriate panel tilt and orientation to enhance sunlight capture 

and to mitigate soiling eff ects

• Correct fusing, switching, and other 

safety considerations

• A system design that incorporates 

functionality and serviceability

• Appropriate attachment details and 

assembly procedures

• Professional workmanship and use 

of proper tools

• Comprehensive system inspection, 

testing, and commissioning

• Experienced program management 

and project oversight

A violation of any one of these components inevitably leads to higher turnkey 

costs, higher maintenance costs, increased 

downtime, and hence poorer economic 

performance. Although the total number 

of required PV panels for a specifi c radar 

site might change as a result of variances 

in the solar resource in diff erent locales, 

the basic design of the system, along 

Figure 1. NWS radar site with the 10-kW 

PV system shown in the foreground.
FEDERAL ENERGY MANAGEMENT PROGRAM — 5 

model PV-10208 (see Figure 2). Th e 

inverter converts the dc power into 

208-volt, 3-phase ac power, which is 

fed through an isolation transformer 

into the utility grid at the site’s main 

service-disconnect switch.

Th e PV system is just outside the fence, 

and its associated switchgear and inverter 

(Figure 3) is just inside the fence. Because 

it is connected electrically to the utility 

side of the transfer switch, the system 

cannot interfere with the generator, or 

vice versa. If the utility power goes down 

or out of tolerance, the code-compliant 

inverter immediately shuts itself off 

and waits for the utility to remain on 

and in tolerance for 5 minutes before 

it reconnects itself. Th e existing UPS 

and backup generator function to 

provide standby power during such 

a grid outage, while the PV system is 

electrically isolated and also ceases to 

generate power.

Th e design team took full advantage of 

the terrain at the Miramar radar site. 

Th e PV array support was engineered to 

use the natural south-facing slope of the 

hill on the south side of the radar dome. 

Th is minimized the environmental 

impact of grading. In addition, there 

is no risk of shading the PV panels 

because there are no trees, and the 

tall radar dome is north of the panels.

A salient design feature of this system 

is the panel-mounting scheme, which 

relies on two 28-ft-long steel I-beams 

upon which the 2.5-kW solar panels are 

mounted. Th e I-beams are mounted 

onto two concrete footings, one at each 

end. Th e standard design routine is to 

place concrete footings every 4 to 8 feet, 

not diffi cult if the ground is fl at and 

fairly even. However, since it was known 

ahead of time that this 2.5-kW building block would have to adapt to many 

diff erent landscapes, fl exibility was 

engineered into the mechanics of the 

system by having only two points of 

contact with the ground. Th is allows 

for versatility in adapting to the varying 

terrain that may be encountered from 

one radar site to the next. Furthermore, 

the I-beams are less expensive than 

numerous concrete footings. Figure 4 

presents an aerial view of the beams, one 

set with the 2.5-kW solar panel attached.

Because the installation is on a southfacing, downward-sloped hill, the 

I-beams are also naturally sloped toward 

the south, thereby permitting the solar 

panels to be attached fl at onto the beams. 

In a fl at-ground installation, the I-beams 

would simply be oriented east-west and 

would accept the attachment of a racked 

assembly of solar panels; the racking system tilts the solar panels upward from 

the horizontal, toward the south. Using 

this standardized, but fl exible, mounting system helps to control costs in 

future installations.

Economic Analysis

Th ree main elements determine the economics of a grid-connected PV system 

like this one:

• Th e net installed cost ($)

• Th e annual energy generation in 

kilowatt-hours per year (kWhac)

• Th e value of displaced energy 

in dollars per kilowatt ac-hour 

($/kWhac)

Figure 2. Layout of PV array, switchgear, and balance of system components.

Figure 3. Balance of system components, including switchgear and inverter.
6 — FEDERAL ENERGY MANAGEMENT PROGRAM

Th e installed or turnkey cost is best 

expressed in terms of dollars per installed 

watt ac ($/Wac). Th e ac rating is derived 

using the Photovoltaics for Utility-Scale 

Applications (PVUSA) dc rating for the 

PV panel provided by the California 

Energy Commission (CEC), multiplied by the number of panels and the 

inverter’s rating.

Th e annual energy generated by the 

system is determined by the available 

solar radiation incident on the array, 

the system size in rated Watts ac, and 

the parasitic losses such as PV panel 

mismatch, wire resistance, inverter 

effi ciency, transformer effi ciency (if 

applicable), average soiling, and general yearly degradation.

Th e customer’s electric bill determines 

the value of displaced energy. Th e cost 

of energy at the NWS Miramar site at 

the time of the PV system design and 

installation was $0.17/kWh. Th is is a 

relatively high rate for electricity compared with some federal sites, which 

makes using alternative energy sources 

such as PV more cost-eff ective. Table 1 

summarizes the cost parameters aff ecting the system economics.

During the fi rst year of operation, 

the system is expected to produce 

16,233 kWh of ac electricity at a 

cost savings of $2760. Although the 

PV system may reduce the site’s peak 

demand charges, that is not guaranteed. 

Th erefore, demand savings were not 

considered in this analysis. Th e overall 

installed cost of the system was $84,792, 

not including the cost of engineering 

and validation, which is a nonrecurring fee for additional future installations using the same design. Th e CEC 

awarded a sizable rebate for this project 

equal to $4.50 per installed Wattac, or 

$43,380. Considering the rebate, the 

fi nal turnkey cost of the system was 

$41,412, about half the usual cost of 

a similarly sized PV system.

To assess the economics of the project, 

a life-cycle cost analysis was completed 

using the Building Life-Cycle Cost 

(BLCC) software tool. Even considering the substantial CEC rebate and 

the high costs of energy at the NWS 

Miramar site, the project is marginally 

cost-eff ective. Th e savings-to-investment 

ratio (SIR) computed for the project is 

0.96; an SIR greater than 1.0 denotes 

a life-cycle cost-eff ective project, according to federal regulations specifi ed in 

10 CFR 436. Th e simple payback period 

is 18 years.

Table 1. Economic analysis parameters and input data.

Description Input Result

Module rating at PVUSA test conditions (Wdc) 105.7

Number of modules 96 10.147 kWdc

Measured inverter effi ciency 0.95 9.640 kWac

Measured transformer effi ciency 0.97 9.351 kWac

Available sunlight, average daily hours 5.6 hours/day 52.364 kWh/day

Number days/year 365 19,113 kWh/yr

Module mismatch factor 0.97 18,540 kWh/yr

Wire resistance loss factor 0.97 17,984 kWh/yr

Average soiling loss factor 0.94 16,905 kWh/yr

Estimated tare loss of transformer during non-sun hours -672 kWh/yr 16,233 kWh/yr

Annual degradation factora 0.99/yr — 0.99/yr —

Estimated energy savings in year 1 16,233 kWh

Facility energy cost at time of case study $0.17/kWh —

Total cost of engineering/validation (non-recurring fee)b $1.56/W $15,000

Total cost of system (supply and build)c $8.80/W $8.80/Wac $84,792 $84,792

CEC rebate amountd $4.50/W $4.50/Wac -$43,380 -$43,380

Turnkey cost, after rebatee $4.30/Wac $41,412 $41,412

a Degradation does not impact system performance until year 2 and for all subsequent years over Degradation does not impact system performance until year 2 and for all subsequent years over a

the life of the system; system performance in year 2 is calculated as 0.99 x 16,406 kWh/yr = 

16,242 kWh/yr; performance in year 3 is 0.99 x 16,242 kWh/yr = 16,080 kWh/yr; and so on

b Design, engineering, and performance validation was funded by the Federal Energy Management Program through the National Renewable Energy Laboratory (one-time fee, not included 

in economic analysis)

c

 Turnkey price (excluding nonrecurring engineering fees) for complete installation

d Actual rebate amount provided by the California Energy Commission (CEC)

e

 Th is fi nal price excludes nonrecurring engineering fees, because future systems can capitalize 

on the preexisting nonrecurring engineering and should be lower in price.

Description Input Result

) 105.7

Number of modules 96 10.147 kW

Measured inverter effi ciency 0.95 9.640 kW

Measured transformer effi ciency 0.97 9.351 kW

Available sunlight, average daily hours 5.6 hours/day 52.364 kWh/day

Number days/year 365 19,113 kWh/yr

Module mismatch factor 0.97 18,540 kWh/yr

Wire resistance loss factor 0.97 17,984 kWh/yr

Average soiling loss factor 0.94 16,905 kWh/yr

Estimated tare loss of transformer during non-sun hours -672 kWh/yr 16,233 kWh/yr

0.99/yr —

Estimated energy savings in year 1 16,233 kWh

Facility energy cost at time of case study $0.17/kWh —

 $1.56/W $15,000

$8.80/W

$4.50/W

$4.30/W

Description Input Result

Number of modules 96 10.147 kW

Measured inverter effi ciency 0.95 9.640 kW

Measured transformer effi ciency 0.97 9.351 kW

Available sunlight, average daily hours 5.6 hours/day 52.364 kWh/day

Number days/year 365 19,113 kWh/yr

Module mismatch factor 0.97 18,540 kWh/yr

Wire resistance loss factor 0.97 17,984 kWh/yr

Average soiling loss factor 0.94 16,905 kWh/yr

Estimated tare loss of transformer during non-sun hours -672 kWh/yr 16,233 kWh/yr

0.99/yr —

Estimated energy savings in year 1 16,233 kWh

Facility energy cost at time of case study $0.17/kWh —

 $1.56/W $15,000

 $84,792

 -$43,380

 $41,412

Figure 4. Aerial view of mounting structure showing I-Beams on concrete footings.
FEDERAL ENERGY MANAGEMENT PROGRAM — 7 

However, traditional economics are 

not the sole determinant in the implementation of alternative energy systems 

such as PV. Besides simply reducing 

energy costs, the NWS Miramar system 

provides additional benefi ts, such as 

protecting the environment by reducing emissions, providing a renewable 

source of energy, preserving natural 

resources, and reducing dependency 

on foreign petroleum products—all 

of which are consistent with both 

NOAA and DOE missions.

Performance Summary

Th e system was offi cially started up 

on August 6, 2002. To ensure that 

the system was operating as designed, 

energy output and peak power output 

were measured for several months after 

start-up. BPA supplied a digital watthour meter and communications module 

to monitor the ac energy production 

of the system. Energy production data 

(in kWh) and peak power output of 

the system (in kW) were collected in 

15-minute periods and downloaded 

each night. Th e data were then analyzed, reduced to daily averages, and 

charted for comparison. Figure 5 

shows the system power and energy 

production during the monitoring 

period of August 6, 2002, through 

October 6, 2002.

Th e data indicate that the system is 

operating well within its expected 

performance range. Th e data also indicate that the system exceeded expected 

performance on some days, as demonstrated by the daily peak power exceeding 

the system-rated power. During the fi rst 

25 days of operation, the system actually 

outperformed expectations by 9.8%, 

averaging 61.53 kWac per day from 

August 7 through August 31, 2002. 

Th e expected average daily output for 

this same period is 56.01 kWac. Of 

course, actual performance is infl uenced predominantly by local weather 

conditions that can cause fl uctuations 

in solar radiation from day to day and 

year to year. Actual performance can 

exceed rated performance when the 

solar insolation and/or the ambient 

temperature fall outside the PVUSA 

standard test conditions (by which the 

system rated power is calculated). Data 

collection continues on this project, and 

system performance can be viewed on 

the BPA Energy Effi ciency web site at 

www.bpa.gov/Energy/N/tech/eemeteringdata/Federal/index.cfm.

Th e value of performance validation 

of grid-connected PV systems cannot 

be overemphasized. In off -grid systems, PV system performance can 

often be judged partly by the performance of other peripheral equipment. 

For instance, excessive generator runtime or battery usage might suggest 

the PV array was not performing as 

expected. However, it can be diffi cult 

to know if grid-connected systems 

are performing as designed without 

regular data collection and analysis, 

because the grid acts as a fairly constant and reliable source of backup 

energy. By continually monitoring 

system performance, the NWS can 

be assured that the system is operating as designed and continuing to 

save energy and costs.

Conclusion

Th e 10-kW PV system installed at NWS 

Miramar is providing reliable power with 

zero emissions. Th e modular design can 

be adapted to any environment to match 

the load requirements of each specifi c 

facility in any area of the country. Now 

that the system design, performance, 

risk, and execution have been proved, 

future systems at other NEXRAD sites 

can be implemented quickly, at low risk, 

and at a lower installed cost.

Th e robust, fl exible PV system design 

developed for the NWS can serve as 

the model for an off -the-shelf system 

for hundreds of future clone sites. 

Th e identical 10-kW system could be 

installed at any one of the NEXRAD 

sites, with actual performance depending 

on site weather conditions. Systems for 

other sites that use this design approach 

should be less costly, since most of the 

nonrecurring engineering can be apportioned to all sites. Th e 10-kWac electrical one-line diagram, the mounting 

details, and the bill of materials (i.e., 

parts list) already exist; engineering at 

clone sites will be limited to determining the best orientation/location for 

the site. Only site-specifi c drawings 

will need to be generated.

Figure 5. Daily measured PV energy production and peak power.
8 — FEDERAL ENERGY MANAGEMENT PROGRAM

Even if NWS decides to consider a 

larger 30-kW system, the modular 

design approach used in this project 

can simplify future installations. For 

example, the PV system design is simplifi ed by the 2.5-kW panel building 

block template and mounting structure. 

Th is modular design approach would 

also apply to systems larger than 10 kW. 

For example, the system could be 

expanded to 30 kW (the peak load 

of the typical NEXRAD radar site) 

by extrapolating the current existing 

10-kW design. Of course, this approach 

would incur additional engineering 

costs, unlike simply replicating the 

design. But from that point on, the 

30-kW design could be considered 

off -the-shelf and applicable to any 

site that could accommodate it.

Th e CEC rebate program vastly 

enhanced the feasibility of the 

Miramar pilot project and could 

be applicable to other PV systems 

installed in California. Focusing 

implementation eff orts on areas with 

high electricity costs and rebate programs like the CEC’s can target the 

most near-term cost-eff ective projects 

for federal applications. Although 

renewable energy systems such as 

PV can provide a host of ancillary 

benefi ts beyond just electricity cost 

reductions, it may be diffi cult for federal agencies to quantify the value of 

those benefi ts. Economics should not 

be the sole determinant for installing 

renewable energy systems. However, 

agencies that can place dollar fi gures 

on the reliability or emissions reductions benefi ts of PV can better justify 

installing these systems on the basis 

of cost alone.

and curtail the load when requested 

to do so by utility system operators 

or at the discretion of the facility 

energy managers.

In the fi rst installation of its kind, the 

PV array and DRS were linked together 

using a control system known as a solar 

load controller (SLC). Th is controller 

automatically monitors the PV electrical output to ensure that it exceeds a 

minimum desired threshold during 

critical periods (e.g., at times of day 

with high utility tariff s). Th is case study 

assesses the fi rst-year performance of 

the USPS Marina’s new PV and DRS.

Background

Th e Marina P&DC is a mail-handling 

facility covering 409,390 ft2 of fl oor 

area in west Los Angeles in the LADWP 

service territory. Th e facility is highly 

Figure 6. USPS Marina Processing & Distribution Center PV Array (G. Marsh, PIX 11015).

Case Study 2: A Combined Building-Integrated Photovoltaic System 

and Demand Response System at a U.S. Postal Service Facility

Overview

Th e U.S. Postal Service (USPS) recently 

implemented a technology demonstration project with the goals of reducing 

(1) peak demand on the grid, (2) the 

facility’s energy costs, and (3) air pollutant emissions. To meet these objectives, the USPS worked with FEMP 

to install a PV array and an automated 

demand-response system (DRS) at the 

USPS Marina Processing and Distribution Center (P&DC) in Marina del 

Rey, California. Th is collaborative project involved Lawrence Berkeley National 

Laboratory, the Los Angeles Department 

of Water and Power (LADWP), and 

private-sector technology providers.

Th e resulting 127-kW rooftop PV 

system, the largest federal buildinginstalled PV system in the nation at 

the time, generates electricity for the 

Marina P&DC directly from sunlight 

(Figure 6). Th e PV system was designed 

to shave up to 10% off the facility’s 

1.2-MW peak power demand and 

save approximately $25,000 per year 

in utility costs. Th e DRS was installed 

to further reduce the peak load for this 

facility. Implemented as part of a pilot 

program operated by CEC, it allows 

building managers to monitor the 

facility’s electrical load in real time 
FEDERAL ENERGY MANAGEMENT PROGRAM — 9 

automated, operating 24 hours per day, 

365 days per year. Historically, this 

site’s daily electricity consumption has 

been relatively constant. Th e more 

than 200,000 ft2 of fl at roof made this 

site an ideal candidate for a buildinginstalled PV system. Th e activities in 

the facility are primarily industrial. 

Two centrifugal chillers provide space 

cooling. Economic incentives available 

at the time of the installation made 

this project particularly attractive. 

Th e CEC funded the entire cost of 

the DRS. Th e installed cost of the PV 

system was approximately $1.03 million. Of this amount, approximately 

$680,000 was covered by a rebate 

from LADWP. In addition, FEMP 

provided a grant to the USPS to cover 

the remainder of the cost of the project, through the FEMP Distributed 

Energy Resources call for projects.

System Description

PV system. Th e Marina P&DC PV system is a lightweight building-installed 

PV roofi ng assembly installed over an 

existing roof membrane (Figure 6). 

Because the roof is fl at, the array has a 

horizontal orientation. Th e PV panels are 

bonded to foam insulation board, 

which provides additional thermal insulation to reduce building heating and 

cooling loads. A 100-kVA inverter converts the dc output from the PV modules 

to ac power. Table 2 shows additional 

system specifi cations. Th e estimated 

annual output is based on simulations 

performed by PowerLight Corporation, 

described in more detail below.

DRS. Th e P&DC DRS was installed as 

part of a project involving several USPS 

sites in response to concerns about peak 

power demand in California. Th e DRS 

is a web-based energy-consumption 

tracking system that collects the facility’s 

energy-consumption data and reports 

those data over the Internet. In addition, 

the system allows the facility’s electrical load to be reduced in response to a 

signal sent over the Internet. Technically, the load curtailment signal can 

be initiated at the site or at a regional 

USPS offi ce. However, the USPS has 

a policy that all curtailments will be 

initiated on site.

Figure 7 shows the DRS network confi guration. Th e DRS hardware consists 

of a network gateway that integrates load 

data from the facility’s chillers and main 

meter. A pulse initiator was installed 

on the existing main utility meter so 

demand reductions could be verifi ed 

when requested by the grid operators. 

Data collected by the gateway are 

uploaded to a central server daily for 

quality control and further analysis. 

Th e gateway is also able to send control signals to cycle the chillers off 

when a curtailment 

is requested. Th e total 

price was $1.2 million 

for 24 sites, or approximately $50,000 per site, 

paid entirely through 

a CEC grant.

SLC. Th e PV array and 

DRS are linked together 

using an SLC, which 

monitors the PV electrical output to ensure 

that it meets or exceeds 

a minimum desired 

threshold during critical periods (e.g., at 

times of day with high 

utility tariff s). If the 

PV system power falls 

below this threshold, 

for instance, as a result 

of cloud cover, the SLC 

will call upon the DRS 

to curtail the building 

load and compensate 

for the reduced PV 

output. In this way, 

Table 2. Marina P&DC PV array characteristics.

Rated Array Capacitya

—Nameplate (DC) 127 kW

—PTC-CEC (DC) 114 kW

—PVUSA simulation (AC)98 kW

Estimated annual output 154,000 kWh

Surface area

—Panels only 11,441 ft2

—Panels plus curbs and walkways 13,618 ft2

Completion date November 2001

Start of data collection May 2002

a Detailed in source report, Monitored Performance of a Building-Integrated Photovoltaic Detailed in source report, Monitored Performance of a Building-Integrated Photovoltaic

System at a U.S. Postal Service Facility, Appendix A, Lawrence Berkeley National Laboratory (LBL-52687), W. Golove et al.

—Panels only 11,441 ft

—Panels plus curbs and walkways 13,618 ft

Completion date November 2001

Start of data collection May 2002

Figure 7. Marina Demand-Response System network 

confi guration.
10 — FEDERAL ENERGY MANAGEMENT PROGRAM

the SLC permits the PV to work in 

tandem with the DRS to provide an 

“assured” level of load reduction for 

the local utility grid. Because the power 

rate paid by the Marina P&DC includes 

a demand charge, the SLC will also serve 

to reduce the building’s peak load and 

resulting demand charges.

Th e SLC is a software application that 

runs on the metering gateway installed 

as part of the DRS at the Marina facility 

(Figure 7). Th e cost of the DRS includes 

the SLC cost. Th e application receives 

several data inputs, including a utility 

rate schedule, real-time demand on 

the controlled devices, and real-time 

generation of the PV array. Th e SLC 

output is the desired demand reduction in kilowatts and a call to the DRS 

for a load curtailment.

Th e SLC is divided into two modules: 

demand reduction and curtailment. Th e 

demand reduction module is responsible for determining the appropriate 

demand reduction in kilowatts if one 

is needed to compensate for lower PV 

output. Th e curtailment module is 

responsible for achieving the desired 

demand reduction by selecting an appropriate level of curtailment for the facility’s equipment. After obtaining the 

necessary operating parameters from 

the confi guration fi les specifi ed by 

the building’s manager, the SLC then 

executes, once per minute, the control 

logic shown in Figure 8.

Once the SLC specifi es the desired 

demand reduction, it is then translated into discrete curtailment steps 

corresponding to the curtailment levels 

implemented at the facility. Th e translation uses a simple look-up table. At 

the USPS Marina facility, there are 

fi ve steps of curtailment, each corresponding to a percentage of load on the 

chillers. Table 3 shows the distribution 

of steps. After the SLC’s curtailment 

module calculates the appropriate curtailment level, it sends an analog (0-20 mA) 

signal to the chiller’s device controllers 

to implement the curtailment.

Curtailment recovery occurs when the 

intended curtailment level is less than 

the one currently implemented. To 

avoid spikes, the SLC maintains curtailment levels for a specifi ed minimum 

duration; these can be specifi ed separately for each curtailment level.

As of August 2003, the DRS has been 

in a monitoring mode, in which facility 

Table 3. Chiller curtailment levels.

 Curtailment

 Step Percentage Chiller Load

 0 100%—no curtailment

 1 80%

 2 65%

 3 50%

 4 35%

 5 0%—full curtailment; 

 chillers shut down

managers receive alerts from the system 

and manually curtail load if needed. 

Th e SLC was expected to be activated 

sometime during the fall of 2003 to 

allow automated curtailments. Th e 

USPS hopes to monitor the SLC’s 

performance during its fi rst year of 

operation to assess it against the 

agency’s technical and fi nancial goals.

PV System Performance

Two performance benchmarks were 

used to assess PV system performance: 

energy generation and peak power 

production. Data collected by the 

site’s data acquisition system (DAS) 

were used to determine the level of 

these energy and demand savings 

and assess them with respect to 

actual weather conditions.

Data collection methodology. As part 

of the PV system installation, PowerLight installed a DAS, consisting of 

a Campbell Scientifi c data logger that 

records ac power (kW), ambient temperature (°C), solar irradiance (W/m2), 

and wind speed (m/s). Th ese four parameters allow for the most effi cient and 

accurate benchmarking and evaluation 

of the system’s performance. Th e data 

logger is fully programmable, with nonvolatile memory and a battery-backed 

clock, mounted in a small, rugged, 

sealed module. Th e sampling rate is 

1 sample per second; average values 

are recorded every 15 minutes. Data 

for the 15-minute averaging periods 

are uploaded nightly to a central server 

and are available on the web for quality 

assurance and further analysis. Data on 

the building load are also logged by the 

demand management system.

Energy. One of the stated goals for 

the Marina PV installation was to 

reduce the facility’s energy consumption. To assess how well this goal has 

been achieved, data for PV electricity 

production were collected and examined from May 2002 through March 

2003 (at the time of publication, a 

full year’s data were not available). 

Th e PV array produced 149,000 kWh 

during this period, shown by month in 

Figure 8. SLC control logic.
FEDERAL ENERGY MANAGEMENT PROGRAM — 11

Figure 9. When designed, it was estimated that the PV array would produce 

154,000 kWh per year or 140,000 kWh 

during the May–March period. Th us 

the actual production exceeded estimates by 6%, during a time when 

the solar insolation [amount of electromagnetic energy (solar radiation) 

incident on the surface of the earth] 

was actually 7% lower than the longterm average (upon which the estimates 

are based). Based on this analysis, it 

appears that the Marina PV installation is performing very well in terms 

of energy production.

PV production and facility load. 

One purpose of this project was to 

reduce the Marina facility’s demand, 

as seen by the utility, through the 

use of distributed generation. To 

assess how well the PV installation 

achieved this goal, we examined the 

facility’s load profi le on the day it 

registered its maximum peak load 

on September 6, 2002.

During the period of maximum building load, the PV system reduced the 

load by approximately 5% (80 kW out 

of 1730 kW). As mentioned earlier, the 

PV system was designed to meet about 

10% of the facility’s peak load. Two 

factors led to the actual contribution’s 

being lower than originally designed. 

First, the actual output of the PV array 

at the time of the facility’s peak demand 

is less than the rated output (because of 

meteorological conditions at the time 

of the facility peak, as well as system 

losses not included in the original system 

rating). Second, since the installation of 

the PV system, another building has been 

added to the Marina P&DC, increasing 

the facility’s peak load by more than 

40% (1700 vs. 1200 kW). At its peak 

output (at noon on July 20, 2002), the 

PV system met approximately 7% of 

the facility’s original 1200-kW demand.

Another important consideration in 

reducing peak loads is how well the 

PV output coincides with both the 

building’s and the utility’s load profi le. 

Figure 10 compares the normalized 

PV output with the building load and 

the system demand for the California 

Independent System Operator (CAISO) 

control area. Th e values shown have 

been normalized to the peak daily value 

for each data series (i.e., PV output is 

expressed as a percentage of peak PV 

output for that day). It appears that 

the peak output of the PV array coincides with the early portion of both the 

facility and the utility system peak.

Figure 10. Relative PV performance on facility peak day. Generation and load profi les 

for Marina PV array, Marina facility load, and CA ISO system demand. Values have been 

normalized to the daily peak value for each data series. Data shown are for the day with 

the highest load for the facility, September 6, 2002. Facility load is the end-use load, 

excluding the effect of PV generation.

Figure 9. Comparison of estimated and measured energy production at USPS Marina 

Postal Processing Center. Measurements for April 2003 were not available yet. Actual 

production exceeded estimated amount by 6% for May–March. Actual production values 

for October–November may be under-represented because of measurement error (still 

under investigation).
12 — FEDERAL ENERGY MANAGEMENT PROGRAM

To assess how well this PV installation 

serves to meet the utility system peak, we 

also made this same comparison for the 

day with peak demand for the CAISO 

control area (Figure 11). Again, the PV 

production appears to peak during the 

hours when the building load and system demand are at peak values. Th e 

fi gures also show periods of reduced 

PV output during these peak demand 

periods, suggesting that the SLC has 

the potential for signifi cant demand 

reduction benefi ts.

Conclusion

Based on approximately one year of 

measured data, the PV system installed 

on the USPS Marina P&DC seems to 

be functioning as planned. In terms of 

energy production, the system produced 

about 6% more than expected, while its 

power output during peak solar periods 

has met or exceeded expectations. During periods of peak demand for the facility, the PV system has met a smaller 

share of the load than expected, mainly 

because the facility (and its load) has 

expanded since the system was originally designed. Th e PV system’s peak 

output coincides fairly closely with 

peak demand for the facility and the 

CAISO utility system.

PV systems are often touted as having 

the ability to reduce peak loads, because 

the peak output of the PV system often 

coincides with the peak demand of the 

facility on which it is installed. Unfortunately, peak reductions from PV systems 

are diffi cult to guarantee because they 

are so dependent on the weather. Historically, the solution to this problem 

involved incorporating energy storage 

into the system to ride through periods 

of lower solar output. Th e system design 

for the Marina P&DC facility, using 

the DRS and the SLC, has the ability 

to ensure peak demand savings as a 

result of the PV installation by controlling building loads based on the 

PV system’s output. To ensure more 

reliable and predictable energy savings, 

systems like this may be the wave of 

the future for PV.

Figure 11. Relative PV performance on utility system peak day. Generation and load profi les for Marina PV array, Marina facility load, and CAISO system demand. Values have 

been normalized to the daily peak value for each data series. Data shown are for the day 

with the highest demand for the CAISO control area, July 10, 2002. Facility load is the 

end-use load, excluding the effect of PV generation.

Case Study 3: Offset-Mounted PV for Low-Slope Commercial Roofs

Overview

To research the potential of PV to 

reduce cooling loads, FEMP, Oak 

Ridge National Laboratory (ORNL), 

and other partners established a PVdistributed energy resource (DER) 

demonstration system at ORNL’s 

Buildings Technology Center (BTC). 

Performance and energy production 

of the off -set mounted PV system is 

continuously monitored and it generates 8.5 kW of peak power. Th e setup 

also is being used to study whether the 

shade that roof-mounted PV systems 

cast on the roofs of commercial buildings can help reduce the cooling load.

Background

Th e higher the exterior temperature of 

a roof, the greater the potential for heat 

transfer into the building, which in turn 

increase the burden on the cooling system during warm months. In the winter, 

the opposite is true: the energy used for 

heating increases as heat is lost through 

the roof. By converting solar energy into 

electricity rather than absorbing it, roofmounted PV systems have the potential 

to reduce cooling loads in commercial 

buildings as they generate power. Data 

describing the benefi t derived from the 

eff ect of PV on mitigating cooling loads 

have been sparse. Th e objective of this 

eff ort is to provide utilities, state and 

federal agencies, the roofi ng industry, 

the solar industry, and the public with 

fi eld data regarding the benefi ts of incorporating PV into commercial buildings. 

Experimental Facility

Th e PV system is mounted on the lowslope roof of the Envelope Systems 
FEDERAL ENERGY MANAGEMENT PROGRAM — 13

Research Apparatus (ESRA), an airconditioned test building at ORNL 

that is east-west oriented to expose large 

areas of roof products (Figure 12). Th e 

ESRA is used to conduct side-by-side 

testing of single-ply membrane roofs 

under the same solar irradiance and climatic conditions. It is sloped at 1/4 in. 

of rise for every 1/2 in. of run (i.e., 

1.2 degrees). Approximately half of 

the ESRA roof (35 ft by 40 ft) is subdivided into ten sections, each consisting 

of a metal deck topped by a 1-in.-thick 

piece of wood fi berboard, a 1/2-in.-thick 

piece of wood fi berboard, and a mechanically attached membrane. Th e metal deck 

is 22-gage, 0.030-in.-thick galvanized 

steel. Th e center module of each test lane 

is instrumented with copper-constantan 

thermocouples and heat-fl ux transducers to measure temperature gradients 

across the roof insulation.

In March 2002, 72 solar panels were 

off set-mounted atop the membranecovered test roofs. A second 72-panel 

array was mounted as an awning shading the south-facing wall of the ESRA 

(Figure 13). Th e PV array was oriented 

facing south for full solar exposure, and 

the slope from the horizontal was fi xed 

at 30 degrees. Th e panels are BP Solar 

model BP MSX120 with dimensions 

of 39 by 43.6 in. and a rated power of 

120 W. Th e conversion effi ciency of the 

MSX120 rated at ASTM standard test 

conditions (STC) is 13.5%, based on the 

active solar cell surface area (ASTM 1996).

Th e PV system is connected to three 

ac-dc Sunny Boy SWR 2500U inverters to convert the dc power generated 

to 3-phase ac. Th e inverters have a rated 

peak effi ciency of 94.1% and use maximum power-point tracking to feed the 

maximum power from the PV array to 

the electric utility grid. Islanding protection is designed into the inverters 

to detect a utility outage and automatically disconnect the inverters from the 

grid, thereby protecting line workers 

troubleshooting the grid. Th e temperature of the PV panels, the dc current, 

dc voltage, and dc power are monitored 

to determine the solid-state conversion 

effi ciency of the PV array. Th e ac power 

output and conversion effi ciency of the 

PV array are also used to document the 

seasonal performance of the system. Th e 

BTC’s weather station also measures 

incident solar fl ux, the air temperature, 

wind speed, and wind direction for estimating the eff ects of weather.

PV Performance

Th e annual average array effi ciency 

of the PV DER system, calculated by 

comparing the electrical output with 

the solar input incident on the panels, 

was found to be 8.8%. Th e best conversion effi ciency for the ORNL system, 

about 9.5%, was observed in March 

through July. Th ose months have the 

highest solar irradiance, peaking in 

June and July.

However, during June and July, the 

PV panel temperature reaches about 

106°F. Th e temperature of solar cells 

strongly impacts system effi ciency: the 

output of commonly used panels drops 

about 4% per 18°F increase in solar 

cell temperature above 77°F STC 

(Hendriks and van de Pol 2000). 

Although April and May had about 

15% fewer hours of solar irradiance, 

the lower panel temperature of 88°F 

in April and May was more conducive 

to conversion effi ciency. Th e rated conversion effi ciency of the solar panels 

(13.5% based on the STC) does not 

consider effi ciency losses as the cell 

temperature exceeds 77°F, dc-to-ac 

conversion losses, and other balanceof-system losses. For the BTC system, 

effi ciency losses were measured at 8.4% 

on average for the year. Th e inverters 

have an advertised peak effi ciency rating of 94.1%. However, on average, 

Figure 12. The Envelope Systems Research Apparatus used for testing painted and 

unpainted metal roofi ng.

Figure 13. Building-integrated photovoltaic (BIPV)(offset-mounted) installed on the 

low-slope membrane roof systems and the south-facing wall of the ESRA.
14 — FEDERAL ENERGY MANAGEMENT PROGRAM

about 91.6% of the dc energy produced by the PV was found to be 

converted to ac energy.

Peak Load Shaving

Th e PV system was coupled to an existing natural-gas-fi red microturbine to 

demonstrate the interaction of multiple 

DER equipment items in a microgrid; 

in this case, the potential to shave the 

electrical loads for the BTC headquarters was demonstrated. Summer loading 

for the building peaks at about 50 kW 

around mid-afternoon. Th e PV and 

microturbine supplied roughly 78% 

of the overall electrical energy used by 

the building from 8 a.m. to 4 p.m. on 

August 4, 1999 (Figure 14). Th e power 

supplied by the PV and microturbine 

also shaved 70% off the building’s 

instantaneous peak demand (which 

occurred at 3 p.m.), reducing demand 

on the grid and saving the building 

owner money.

Th e microturbine consumes about 

417,000 Btu/h of natural gas to produce a steady output of 28 kW. Th e 

renewable energy generated by the 

8.5-kWp PV array and the micro turbine 

is about 64 MWh per year, assuming 

2000 hours of turbine operation. Th e 

annual load for the BTC headquarters 

is 184 MWh. Given these inputs, the 

energy sav ings delivered by the microgrid (PV with microturbine) is 64,050 

kWh/year or 34.7%. ORNL pays only 

about $0.048 per kWh for electricity. 

Th e price of natural gas has fl uctuated 

but at the time of this writing was about 

$4.50 per decatherm. Th e cost of natural gas consumed by the microturbine 

for 2000 hours of operation is roughly 

$3753. Th e 64-MWh electrical savings costs only $3075, which includes 

the renewable energy supplied by the 

PV system. Th erefore, there was no 

cost benefi t compared with utilitysupplied electrical energy. However, 

the system provided electricity during 

the peak demand period when grid 

power was most limited and most 

expensive. It also provided power at 

mission-critical periods.

Thermal Performance 

of Roofs with OffsetMounted PV

Th e heat-fl ux transducers placed in the 

test roofs helped quantify the indirect 

shading benefi t from the off set-mounted 

PV system. Th e ESRA fi eld data for 

the test built-up roof (BUR) with R-5 

insulation shows a signifi cant drop in 

membrane temperature. Two diff erent 

summer weeks of data, one with the 

ESRA fully exposed to solar irradiance 

and the other with it shaded by the PV, 

are displayed in Figure 15. Both data sets 

had clear skies and similar outdoor ambient air temperatures. Shading the dark 

absorptive BUR reduced the surface temperature by about 60°F at around solar 

noon (Figure 15), reducing the solar 

Figure. 14. The PV and microturbine supplied roughly 78% of the overall electrical 

energy used by the BTC headquarters from 8 a.m. to 4 p.m. on August 4, 1999.

Figure 15. Biomass growth in shaded and fully exposed sections of thermoplastic 

membranes.
FEDERAL ENERGY MANAGEMENT PROGRAM — 15

heat gain by a factor of four. Th e heat 

fl ux to the building interior dropped 

from 20 to about 5 Btu/h•ft2. Th e reduction may signifi cantly reduce the building’s cooling load. However, the results 

must be generalized into a rating procedure that accounts for the ranges of roof 

insulation, of refl ectance and emittance 

typically found on low-slope roofi ng, 

and of climates to which commercial 

roofi ng is exposed.

Shading Increases 

Roof Soiling

Exposed thermoplastic membranes in 

some U.S. climates tend to lose 30-50% 

of their refl ectance over several years 

because biomass accumulates and attracts 

airborne contaminants that soil the 

roofs. Th e shading provided by the PV 

array on the ESRA apparently helped 

the biomass thrive on the roof membranes (Figure 15), as portions of the 

membranes fully exposed to sunlight 

did not show the accelerated growth 

observed on the shaded areas (see 

inserts in Figure 16). Th e TPO and 

PVC membranes had lost 31% and 

40% of their initial refl ectance, respectively, while fully exposed for 4 years. 

However, the sections shaded by the PV 

array lost more than 65% of their refl ectance. Th e accelerated biomass growth 

does not necessarily aff ect the thermal 

performance of the membranes; however, it may pose a health hazard and 

aff ect the durability of the materials.

Offset-Mounted PV 

Computer Simulations

Th e Simplifi ed Transient Analysis of 

Roofs (STAR) computer code was used 

to compare the thermal effi ciency of 

a roof with PV to that of a conventional insulated roof for various U.S. 

climates. Th e code models transient 

one-dimensional heat fl ow through the 

exterior roof cover, through multiple 

layers of roof insulation, and through 

the supporting subframe. Simulations 

generated the heat fl ux entering or 

leaving the conditioned space for a 

range of roof radiation properties, insulation levels, and deck constructions. 

Roof insulation levels ranged from R-5 

through R-30 with and without PV for 

the climates of Phoenix; Long Beach, 

California; Knoxville, Tennessee; 

Seattle; and Minneapolis.

Simulations were run for TPO (R87E93)1

and PVC (R81E94) thermoplastic membranes, a white painted PVDF metal 

(R64E83), and a dark BUR (R05E90). 

Modeled cooling load savings are shown 

for Phoenix in relation to the level of 

roof insulation (Figure 17). Savings are 

based on the diff erence in cooling load 

between a roof with PV and the same 

roof fully exposed to the elements. Th e 

ancillary shading is greatest for a dark, 

absorptive BUR. Th e trends were similar for a white painted metal roof with 

PV, but the benefi t was less because 

the more refl ective painted metal performs better thermally than an exposed 

dark BUR. Off set-mounted PV on a 

BUR with R-5 insulation saves about 

16,000 Btu/ft2 because the shading drops 

the surface temperature to just above 

the outdoor ambient temperature. Based 

on ASHRAE Standard 90.1 (1999), the 

minimum insulation level for nonresidential, low-slope roofi ng in Phoenix 

is R-15, and the annual savings for an 

R-15 BUR with PV is about 4000 Btu/ft2

of shaded roof. Th erefore, realistic cooling savings range from 4000 to 8000 Btu/

ft2 of shaded roof (R-15 and R-10 roofs, 

respectively) in Phoenix.

For the TPO and PVC membranes, 

off set-mounted PV actually increased 

the heat penetrating into an Arizona 

roof. Increasing the insulation lessened 

the penalty (Figure 17); however, the 

results indicate that placing PV on an 

existing highly refl ective roof increases 

the cooling load because of heat transfer between the PV panels and the roof. Figure 16. ESRA fi eld data for a fully exposed BUR and the same BUR shaded by BIPV.

1 Each roof is described generically using an RxxEyy designation. Rxx states the solar refl ectance of a new sample, 1.0 being a perfect refl ector. Eyy 

defi nes the infrared emittance of the new sample, 1.0 being blackbody radiation. For example, the built-up roof is labeled R05E90. Its surface properties are therefore 0.05-refl ectance and 0.90-emittance.
16 — FEDERAL ENERGY MANAGEMENT PROGRAM

At solar noon for August in Knoxville, 

the PV panels would reach an underside 

temperature of about 155°F. An exposed 

thermoplastic membrane would refl ect 

roughly 80% of the incident solar irradiance and much of the infrared heat 

back to the sky. Th e heat gain resulting from the PV panels exceeds their 

shading benefi t. Th e results imply 

that a roof designed according to new 

energy-effi cient building codes would 

deliver less benefi t from PV than existing building stock with less insulation 

and lower refl ectance.

Attaching laminated PV (R26E90) 

directly to a refl ective membrane 

caused an even greater penalty. Th e 

membranes are about 85% refl ective; 

the laminate PV, only about 26%. 

Th e lower refl ectance increased solar 

absorptance, and the 5% conversion 

effi ciency for the PV laminate did not 

compensate for the increased solar 

fl ux. Placing the laminate on a thermoplastic membrane roof in Phoenix 

would cause the energy transfer from 

the roof to increase by 5000 Btu/ft2

for insulation levels above R-20.2

In mostly heating climates, refl ective 

membranes are not preferred because 

they refl ect solar energy that would help 

heat the building during the winter, 

causing an energy penalty that exceeds 

cooling savings in the summer. However, according to the simulation results, 

PV placed on an existing refl ective roof 

cover in a cold climate would reduce the 

heating burden because of the radiosity 

exchange between the PV and the roof 

and because the panels limit nighttime 

radiation losses from the roof.

In the predominantly heating climate 

of Minneapolis, the shading eff ect from 

placing off set-mounted PV onto a BUR 

increased the building’s heating demand 

compared with a fully exposed BUR 

(Figure 18). Th erefore, in heating climates, laminate PV should be used 

instead of a PV array off set from the 

roof. Simulations conducted for a PV 

laminate (R26E90) showed no annual 

net penalty in building load; hence, 

direct laminate is well suited to PV 

installations in heating climates.

Th e model predicts signifi cant net 

annual savings for off set-mounted 

PV in Phoenix, Knoxville, and Long 

Beach (Figure 19) and energy penalties 

for the climates of Minneapolis and 

Seattle. Energy savings are predicted 

to drop exponentially as the roof insulation increases from R-5 through R-30 

(Figure 19). Natural gas prices are 

roughly $6.70 per decatherm, and 

electricity costs about $0.08 per kWh 

in Phoenix. For these fuel prices and 

the energy savings of Figure 19, the 

predicted annual cost savings per 

square foot of low-slope roof using 

roof-mounted, off set PV arrays could 

be as high as $0.18 in that city. For the 

more moderate climate of Knoxville, 

Tennessee, the savings would be about 

$0.06 per square foot per year.

2 R-20 represents about 5 in. of expanded polystyrene insulation.

Figure. 18. Annual heating load savings with offset-mounted PV.

Figure. 17. Annual cooling load savings with offset-mounted PV array, Phoenix, Arizona.
FEDERAL ENERGY MANAGEMENT PROGRAM — 17

Summary

Data from this study show that shading from an off set-mounted PV system 

drops roof temperature to only about 

5°F warmer than the outdoor air temperature. Based on these results, a PV 

system installed on a built-up lowslope roof system in Phoenix can provide space-cooling savings as high as 

$0.18 per square foot of roof area per 

year. Almost 70% of new and existing 

low-slope commercial roofi ng in the 

western United States is fi nished in 

dark roofi ng. Placing off set-mounted PV 

on such a roof in a mostly cooling climate can signifi cantly reduce roof energy 

loss. However, a similar system on a 

highly refl ective thermoplastic membrane results in an energy penalty in 

cooling climates. Adding laminate PV, 

which is less refl ective, exacerbates the 

penalty; even with R-20 insulation, the 

net energy load increases by 5000 Btu/ft2

per year compared with exposed refl ective membranes.

In predominantly heating climates, off setmounted PV on a BUR increases the 

energy load for insulation levels from 

R-5 through R-30. In Minneapolis, 

laminate PV would supply renewable 

energy without an energy penalty on an 

annual basis because the heating-load 

penalty matches the cooling-load benefi t of the 26% refl ective laminate.

Conclusion

Eff ective use of PV technology can 

help the federal sector meet its goals 

of reducing energy consumption and 

expanding the use of renewable energy 

in the federal sector. PV systems like 

those discussed in this report may help 

federal facilities integrate PV into their 

energy mix. 

Th is review examined some of the costs 

and benefi ts of PV systems and associated technologies for federal facilities. 

Potential benefi ts of installing PV systems at federal facilities include these: 

• Reliability—they operate for long 

periods with little maintenance.

• Low operating costs—the fuel is free, 

and there are few, if any, moving parts.

• Low environmental impact—they 

are quiet and nonpolluting (no 

greenhouse gas emissions) and 

require no air permitting.

• Standalone capability—they can 

operate in remote areas far from 

power lines.

• Modularity—power output can be 

increased by adding more panels.

• Safety—they are not fl ammable 

and meet National Electric 

Code requirements.

• Versatility—they operate well in 

almost any climate.

• Ease of installation—no heavy construction equipment is required.

• Grid support—they provide energy 

security in areas where electricity 

shortages are anticipated.

In addition, as is discussed in the case 

studies, roof-mounted PV systems provide shade for roofs and so may reduce 

solar heat gain and the resulting extra 

cooling required during the summer. 

At facilities where electricity demand 

is increasing, installing PV to handle 

the growth may be less costly than 

expanding existing electrical distribution equipment. In most of the country, peak electrical demand occurs 

during the sunniest times of the day, 

which is when PV energy production 

is at its peak. PV can be used to off set 

demand during those hours, reducing 

the stress on the utility grid and avoiding extra cost for power purchased 

during peak demand periods.

Although most cost-eff ective PV installations in the past were for remote, off -grid 

power applications, current installations 

include high-value grid-connected applications that provide reliable power, 

reduce energy consumption and costs, 

and reduce harmful emissions. Th e 

systems included in the case studies 

for this technology focus are all gridconnected. Th e economic analyses conducted for these projects indicate that 

grid-connected PV systems are not likely 

to meet traditional cost-eff ectiveness 

criteria (e.g., brief payback periods) if 

only energy cost savings are considered. 

For example, a life-cycle cost analysis 

of the PV system at the NEXRAD facility in Miramar indicated that even with 

a substantial rebate from the local utility 

and above-average electricity rates, the 

project was marginally cost-eff ective in 

traditional economic terms. Th e simple 

payback period for the project is 18 years.

Figure 19. Annual building load savings with offset-mounted PV on a BUR (R05E90).
18 — FEDERAL ENERGY MANAGEMENT PROGRAM

However, economics is not the only 

factor to consider in determining 

whether to implement renewable 

energy systems such as PV. Besides 

reducing energy costs, PV may provide signifi cant security, operational, 

and environmental benefi ts such as 

reducing harmful emissions from power 

plants, reducing demand on the electrical grid, enhancing energy reliability 

and security, and aiding the development of renewable sources of energy. 

Agencies that can place a dollar value 

on benefi ts such as those will be better 

able to justify installing these systems 

on the basis of cost.

Still, capital cost remains a major challenge to widespread implementation. 

Although the cost of PV panels has 

dropped to less than $6 per watt (compared with $100 per watt 30 years ago), 

making use of rebate programs and identifying ancillary benefi ts from PV systems 

are crucial to fi nding cost-eff ective applications. Some ways to improve the economics of PV systems include

• Recognizing and valuing the ancillary benefi ts of PV installations, 

such as reduced emissions or more 

reliable power

• Integrating PV into the building 

itself, for example, installing a PV 

system during a regular roof replacement or considering a PV carport 

when new covered parking is needed 

so building material costs are off set

• Obtaining rebates for PV systems 

(available only in some parts of the 

country) to reduce the capital costs

• Using federal fi nancing mechanisms 

such as energy savings performance 

contracts to reduce the initial cost 

of grid-connected PV systems

As PV costs continue to decrease, utility costs continue to increase, and it 

becomes easier to procure and install 

PV systems, PV should become more 

accessible and more economically feasible for federal facilities.

Two existing grid-connected PV installations that supply power to federal 

facilities—a 10-kW ground-mounted 

system for the NEXRAD radar system 

at the NWS Miramar facility and a 

127-kW rooftop system at the USPS 

Marina Processing and Distribution 

Center—were described, as well as a 

grid-connected PV system at ORNL 

that was installed for research purposes.

Results from the case studies show that 

all three systems met or exceeded performance expectations in terms of operating effi ciency and power output. Data 

collected for the USPS system comparing 

PV output with the facility’s load profi le showed that PV production peaks 

during the hours when the facility’s 

power requirements and demand on 

the utility system are also at a peak, 

indicating that PV can be useful in 

helping facilities alleviate stress on the 

utility grid and avoid extra costs that 

many utilities charge for power purchased during peak periods.

One of the purposes of the system 

installed at ORNL was to assess 

whether the shading on a roof from 

off set-mounted PV panels reduces 

heat gain from the roof and thus trims 

cooling energy use during hot weather. 

Th e results show that the benefi t depends 

upon the type of roof covering, the 

amount of roof insulation installed, 

and the climate of the area. Th e shading 

benefi t is greatest for dark built-up roofs 

that absorb large amounts of heat. Th e 

less insulation the roof has, the greater 

the energy savings due to the shading. 

For highly refl ective membranes that 

refl ect most solar energy back to the sky, 

however, off set-mounted PV actually 

increases energy consumption because 

the energy penalty from heat transfer 

between the panels and the roof exceeds 

the shading benefi t. In colder climates, 

the shading eff ect of off set-mounted 

PV panels generally resulted in higher 

demand for heating in the winter that 

exceeded cooling savings in the summer. 

Overall, modeling results indicate that 

the shading provided by off set-mounted 

PV off ers signifi cant energy savings in 

predominantly cooling regions and 

energy penalties in predominantly 

heating climates. 

Beyond simply describing the PV and 

related technologies involved in these 

installations, the case studies provided 

insight into the potential sources of 

benefi ts associated with them. Th e fi rst 

and most obvious benefi t is the fi nancial 

savings from reduced utility charges. 

Generally, it can be broken down into 

two components, reduced energy charges 

and reduced demand charges. Th e future 

value of the lower energy charges is relatively easy to forecast. However, reduced 

demand charges, although potentially of 

greater magnitude, are less predictable 

and currently less manageable. PV system 

output cannot be reliably controlled 

and can vary from minute to minute; 

therefore, although particular PV systems have been shown to reduce peak 

demand, the reductions are not dependable. Th e USPS case study describes 

one approach, the use of a solar load 

controller that is being used to increase 

the manageability and predictability 

of reduced demand charges. If successful, this type of system could be 

used in future PV installations to 

help ensure the reliability of peak 

demand reductions.

As described in the ORNL case study, 

recent research indicates potential additional savings associated with rooftop 

PV systems in particular—utility cost 

reductions resulting from the shading 

provided by the PV systems. 

In addition to the energy and cost saving 

benefi ts, these case studies highlight 

ancillary benefi ts associated with PV 

systems, such as reducing the air pollution associated with conventional 

electricity generation, and preserving 

natural resources. Th ese are all of tremendous social signifi cance and are 

consistent with the goals and objectives 

of the federal government. PV systems 

can also make important contributions 

to reducing peak energy demand across 

local and regional grids. Given the cost 

of peak power and the value of electricity 

reliability in many parts of the country, 

this benefi t is signifi cant. And simply 

diversifying the mix of energy generation at federal facilities can enhance 

homeland security.
FEDERAL ENERGY MANAGEMENT PROGRAM — 19

Th ere are, however, limits to the benefi ts of PV systems that should be recognized. All the systems described in 

this document benefi ted greatly from 

subsidies from outside organizations; 

without the subsidies, the costs of these 

systems would have outweighed their 

economic benefi ts. In most parts of the 

country, no subsidies are available; without them, the life-cycle cost of these 

systems may not be attractive. Further, 

utility rates in California, where the 

NWS and USPS systems are located, 

are among the highest in the country, 

which further contributed to the economic attractiveness of these systems. 

PV remains expensive, and locations 

with high utility rates and subsidies 

are good geographic targets that can 

result in the most cost-eff ective systems. Agencies that can place dollar 

fi gures on the reliability or emissions 

reductions benefi ts of PV can also better 

justify installing these systems based 

on economics.

Finally, uncertainty surrounding demand 

reduction benefi ts can further reduce 

PV’s appeal. Th ose limitations notwithstanding, the case studies presented in 

this document clearly illustrate instances 

where PV installations have proved 

benefi cial to federal agencies. As the 

price of PV systems goes down and as 

better control over the peak reduction 

benefi ts is achieved, PV technologies 

will continue to increase their contribution to our national energy systems.

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Produced for the U.S. Department 

of Energy, Energy Effi ciency and Renewable Energy, by the Oak Ridge National 

Laboratory

DOE/EE-0308

April 2005

For More Information

EERE Information Center

1-877-EERE-INF or 

1-877-337-3463

www.eere.energy.gov/femp

General Program Contacts

Ted Collins

New Technology Demonstration 

 Program Manager

Federal Energy Management 

 Program

U.S. Department of Energy

1000 Independence Ave., SW, EE-92

Washington, D.C. 20585

Phone: (202) 586-8017 

Fax: (202) 586-3000 

theodore.collins@ee.doe.gov

Steven A. Parker

Pacifi c Northwest National 

 Laboratory

P.O. Box 999, MSIN: K5-08 

Richland, WA 99352

Phone: (509) 375-6366

Fax: (509) 375-3614

steven.parker@pnl.gov

Technical Contacts and Authors

Case Study 1: NWS Miramar, CA

Trina Masepohl

National Renewable 

 Energy Laboratory

Phone: (303) 384-7518

trina_masepohl@nrel.gov

Case Study 2: USPS Marina 

 del Rey, CA

William H. Golove

Lawrence Berkeley 

 National Laboratory

Phone: (510) 486-5229

WHGolove@lbl.gov

Case Study 3: ORNL, Oak Ridge, TN

William A. Miller

Oak Ridge National Laboratory

Phone: (865) 574-2013

millerwa1@ornl.gov

Disclaimer

This report was sponsored by the United States Department of Energy, Energy Effi ciency and 

Renewable Energy, Federal Energy Management Program. Neither the United States Government 

nor any agency or contractor thereof, nor any of their employees, makes any warranty, express 

or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or 

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