Facility-Scale Solar

Photovoltaic Guidebook
Bureau of Reclamation
Kosol Kiatreungwattana, Otto VanGeet, and
Blaise Stoltenberg
National Renewable Energy Laboratory

Produced under direction of the Bureau of Reclamation by the

National Renewable Energy Laboratory (NREL) under IAG-14-1950
and Task No WFGX.1021.

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

Office of Energy Efficiency & Renewable Energy
Operated by the Alliance for Sustainable Energy, LLC
This report is available at no cost from the National Renewable Energy
Laboratory (NREL) at www.nrel.gov/publications.

Strategic Partnership Project Report

NREL/TP-7A40-67122
September 2016

Contract No. DE-AC36-08GO28308

 Facility-Scale Solar
Photovoltaic Guidebook
Bureau of Reclamation
Kosol Kiatreungwattana, Otto VanGeet, and
Blaise Stoltenberg
National Renewable Energy Laboratory

Prepared under Task No. WFGX.1021

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

Office of Energy Efficiency & Renewable Energy
Operated by the Alliance for Sustainable Energy, LLC
This report is available at no cost from the National Renewable Energy
Laboratory (NREL) at www.nrel.gov/publications.

National Renewable Energy Laboratory Strategic Partnership Project Report

15013 Denver West Parkway NREL/TP-7A40-67122
Golden, CO 80401 September 2016
303-275-3000 • www.nrel.gov
Contract No. DE-AC36-08GO28308
 NOTICE

This manuscript has been authored by employees of the Alliance for Sustainable Energy, LLC (“Alliance”) under
Contract No. DE-AC36-08GO28308 with the U.S. Department of Energy (“DOE”).

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
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 Acknowledgments
The National Renewable Energy Laboratory team thanks the United States Bureau of
Reclamation for the opportunity to develop the Facility-Scale Solar Photovoltaic Guidebook. In
particular, the team is grateful to Reclamation’s Erin Foraker, Art Coykendall, Cathy
Cunningham, Lynn MacDonald, Lance Marbut, and Kerry Whitford, for their guidance and
generous assistance throughout the development. In addition, the team would like thank Paula
Engel for her supporting document, The Basics of Life Cycle Cost Analyses Supporting
Reclamation’s Sustainable Energy Goals.

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 List of Abbreviations and Acronyms
AC alternating current
ACHP Advisory Council on Historic Preservation
a-Si amorphous silicon
BIPV building integrated photovoltaics
BOS balance-of-system
CdTe cadmium telluride
CEQ Council on Environmental Quality
CIGS copper indium gallium selenide
CR cultural resources
DC direct current
DHI diffuse horizontal irradiance
DNI direct normal irradiance
DOI U.S. Department of Interior
EA environmental assessment
ECMs energy conservation measures
EE energy efficiency
EIS environmental impact statement
EISA Energy Independence and Security Act
E.O. Executive Order
EPA U.S. Environmental Protection Agency
EPAct Energy Policy Act
ESCO energy services company
ESPC energy savings performance contract
FEMP Federal Energy Management Program
FIT feed-in-tariff
GHG greenhouse gas
GHI global horizontal insolation
IRR internal rate of return
kW kilowatt
kW/m2 kilowatt per square meter
kWh kilowatt-hour
kWh/m2 kilowatt-hour per square meter
LCC life cycle cost
LCCA life cycle cost analysis
LCD liquid-crystal display
LEED Leadership in Energy and Environmental Design
MIRR modified internal rate of return
mph miles per hour
MW megawatt

ii

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 NEC National Electrical Code
NEPA National Environmental Policy Act
NHPA National Historic Preservation Act
NPV net present value
N-HRE non-hydro renewable energy
NREL National Renewable Energy Laboratory
OMB Office of Management and Budget
O&M operation and maintenance
PPA power purchase agreement
PV photovoltaic
REC renewable energy credit
RFP request for proposal
SAM System Advisor Model
SIR savings-to-investment ratio
TOU time of use
UESC utility energy services contract
W watt

iii

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 Table of Contents
1 Introduction ........................................................................................................................................... 1
1.1 Making the Case for Reclamation Facility Solar Energy Projects ................................................ 1
1.2 Legal and Regulatory Framework ................................................................................................. 2
1.2.1 Federal Renewable Energy Requirements ....................................................................... 2
1.2.2 Other Renewable Energy Requirements .......................................................................... 4
2 Solar Resource ..................................................................................................................................... 5
3 PV System Components ...................................................................................................................... 8
3.1 How PV Works ............................................................................................................................. 8
3.2 Major System Components ........................................................................................................... 9
3.2.1 PV Module ..................................................................................................................... 10
3.2.2 Inverter ........................................................................................................................... 12
3.2.3 Balance-of-System Components .................................................................................... 13
3.2.4 Battery ............................................................................................................................ 16
3.2.5 PV System Monitoring ................................................................................................... 17
4 Solar Energy System Siting: General Technical and Site Specific Considerations .................... 17
4.1 Solar Collector Access to the Sun and Calculation of Available Area ....................................... 18
4.2 Rooftop Solar Considerations ..................................................................................................... 20
4.3 Ground Mount Solar Considerations........................................................................................... 21
4.4 General Site Considerations ........................................................................................................ 21
4.4.1 Historic Preservation and Environmental Laws - General Considerations .................... 22
4.4.2 Utility Requirements ...................................................................................................... 24
4.4.3 Balance-of-System Placement........................................................................................ 25
4.4.4 Site Master Plan ............................................................................................................. 25
4.4.5 Computer Network Connectivity Authority ................................................................... 25
4.4.6 Climate Considerations .................................................................................................. 26
4.4.7 Vegetation Considerations ............................................................................................. 27
5 System Sizing and Energy Production Estimation ......................................................................... 27
5.1 System Sizing .............................................................................................................................. 27
5.1.1 Project goals ................................................................................................................... 27
5.1.2 Site Load ........................................................................................................................ 27
5.1.3 Utility Requirements and Rate Structures ...................................................................... 29
5.1.4 Available Area................................................................................................................ 29
5.2 Energy Production Estimation..................................................................................................... 30
5.2.1 Software Tools for Estimating Energy Production ........................................................ 30
5.2.2 Energy Production Estimation and Collector Orientation .............................................. 33
6 Cost Overview ..................................................................................................................................... 34
6.1 Cost Trends and General Rule of Thumb for PV Costing........................................................... 34
6.2 Cost per Watt Breakdown ........................................................................................................... 35
6.3 Operation and Maintenance......................................................................................................... 36
7 Economic Analysis and Business Structures ................................................................................. 38
7.1 Economic Analysis ...................................................................................................................... 38
7.1.1 Life Cycle Cost Analysis................................................................................................ 38
7.1.2 Savings-to-Investment Ratio .......................................................................................... 38
7.1.3 Modified Internal Rate of Return ................................................................................... 38
7.2 Factors Affecting Economic Analysis Inputs .............................................................................. 39
7.2.1 Utility Tariff Structures .................................................................................................. 39
7.2.2 Available Incentives ....................................................................................................... 39
7.2.3 Ownership Models ......................................................................................................... 40
8 Project Execution ............................................................................................................................... 41
8.1 Identify needs and goals .............................................................................................................. 42

iv

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 8.2 Assemble an onsite team ............................................................................................................. 42
8.3 Evaluate candidate solar energy sites .......................................................................................... 43
8.4 Consider project requirements and recommendations ................................................................ 43
8.5 Make a financing and contracting decision ................................................................................. 43
8.6 Follow the process for the financing and contracting method selected....................................... 44
Appendix A. Self-Guided Solar Screening ............................................................................................. 45
Appendix B. Summary of Preliminary Solar Energy Site Screening for Photovoltaics .................... 48
Appendix C. Solar Screening Evaluation Checklist .............................................................................. 50
Appendix D. PV Project Design Evaluation Checklist........................................................................... 54
Appendix E. PV Commissioning Checklist ............................................................................................ 57
Appendix F. Example of Requirements for a PV System...................................................................... 59
Appendix G. Service Descriptions for Preventive Maintenance .......................................................... 72
Appendix H. Service Descriptions for Corrective Maintenance ........................................................... 77
Appendix I. The Basics of Lifecycle Cost Analyses Supporting Reclamation’s Sustainable Energy
Goals .................................................................................................................................................... 80
Appendix J. National Alliance of Preservation Commissions – Sample Guidelines for Solar
Systems in Historic Districts, National Park Service – Incorporating Solar Panels in
Rehabilitation Project ....................................................................................................................... 124

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 List of Figures
Figure 1. States with Reclamation’s operations and facilities ...................................................................... 1
Figure 2. A common energy reduction hierarchy ......................................................................................... 4
Figure 3. Solar irradiance .............................................................................................................................. 6
Figure 4. Hourly clear sky solar irradiance, Golden, Colorado .................................................................... 7
Figure 5. Hourly partly cloudy sky solar irradiance, Golden, Colorado ...................................................... 7
Figure 6. Generation of electricity from a PV cell ........................................................................................ 8
Figure 7. Ground mount array diagram ........................................................................................................ 9
Figure 8. Roof mount array diagram............................................................................................................. 9
Figure 9. PV panel rating for wind, snow, and hail loads ........................................................................... 10
Figure 10. Crystalline solar modules .......................................................................................................... 11
Figure 11. Thin-film solar modules (left) and building integrated photovoltaics (right) ............................ 12
Figure 12. String inverter (left) and microinverter (right) .......................................................................... 13
Figure 13. Anchored and ballasted PV mounting systems ......................................................................... 14
Figure 14. PV system with fixed tilt ........................................................................................................... 15
Figure 15. PV system with single-axis trackers .......................................................................................... 15
Figure 16. PV system with dual-axis trackers............................................................................................. 16
Figure 17. PV system with battery pack ..................................................................................................... 17
Figure 18. Sun path ..................................................................................................................................... 19
Figure 19. SunEye shade analysis ............................................................................................................... 20
Figure 20. Photovoltaic solar resource........................................................................................................ 26
Figure 21. PVWatts..................................................................................................................................... 31
Figure 22. PVWatts results for a 1 kW system ........................................................................................... 32
Figure 23. Screen shot of the System Advisor Model outputs .................................................................... 33
Figure 24. Effect of collector orientation .................................................................................................... 34
Figure 25. Average PV system cost from Q1 2013 to Q2 2015 ................................................................. 35
Figure 26. Cost contributions of PV system components ........................................................................... 36

List of Tables
Table 1. Energy density by panel and system for ground-mounted PV...................................................... 30

vi

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 1 Introduction
The National Renewable Energy Laboratory (NREL) has an interagency agreement with the U.S.
Bureau of Reclamation (Reclamation) to explore the use of non-hydro renewable energy (N-
HRE) resources to meet the U.S. Department of Interior’s objectives and Reclamation’s mission.
Under that agreement, NREL was contracted to develop a facility-scale solar photovoltaic (PV)
guidebook for Reclamation. This guidebook presents readers with the processes and steps needed
to assess and successfully implement facility-scale solar projects. Each part has several substeps
and considerations.

1.1 Making the Case for Reclamation Facility Solar Energy Projects
Reclamation is the largest wholesale water supplier and the second largest producer of
hydroelectric power in the United States, with operations and facilities in the 17 western states.
Reclamation has a long and successful history providing renewable, clean, reliable, and
affordable hydropower to its customers. As technology and demands for power and water use
evolved over the last 100-plus years, Reclamation adapted to take advantage of new ways to help
meet the nation’s water and energy needs. As the agency moves well into its second century,
Reclamation plays an important role in developing and supporting renewable energy production
and the development, conservation, and integration of emerging renewable energy technologies
into the nation’s power grid.

Reclamation continues to improve and enhance our renewable hydropower capabilities, but will
also support the development of other N-HRE, such as wind, solar, and geothermal, where it
supports the agencies mission and goals. Figure 1 presents states where Reclamation’s operations
and facilities are located. The majority of these states have excellent solar resources.

Figure 1. States with Reclamation’s operations and facilities

Reclamation’s facilities such as office buildings, small pumping plants, and water treatment
facilities could potentially use solar energy to meet all or a portion of the facility load. Solar
energy is practical for meeting facility-scale needs and can be placed at different locations at a
facility such as a roof or parking lot.

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 Facility-scale solar is most feasible where:
• Energy prices are high: >$0.09-$0.10 per kilowatt-hour (kWh)
• Incentives are available to subsidize the cost of PV installation, such as tax credits, local
utility incentives, and renewable energy portfolio usage targets found in California,
Arizona, Colorado, and New Mexico
• Sufficient space is available on rooftops, parking lots, or adjacent open land to site a solar
installation capable of meeting a significant fraction of facility demand.

A combination of these factors makes the economics most attractive for investment in a facility-
scale installation.

1.2 Legal and Regulatory Framework

As the nation’s largest energy consumer, the federal government presents a tremendous
opportunity for jump-starting a significant increase in domestic solar production. However, the
solar installations must be implemented with appropriate consideration for other legal
requirements (see section 4.4.1). The following subsections summarize some of the current laws
and regulations defining federal renewable energy requirements and other laws that must be
considered when planning and installing renewable energy systems.

1.2.1 Federal Renewable Energy Requirements

Executive Order (E.O.) 13693, Planning for Federal Sustainability in the Next Decade, signed
on March 25, 2015, sets sustainability goals for federal government facilities that increase and
improve their environmental performance, protect the planet for future generations, reduce
spending, and increase efficiency and resilience. They key unifying goal within E.O. 13693 is to
reduce agency greenhouse gas (GHG) emissions, with a stretch target of at least 40% by 2025.

E.O. 13693 requires that each agency propose to the Chair of the Council on Environmental
Quality (CEQ) and the Director of the Office of Management and Budget (OMB) percentage
reduction targets for agency-wide reductions of GHG emissions in absolute terms by the end of
fiscal year 2025 relative to a fiscal year 2008 baseline. The Department of the Interior proposed,
and CEQ accepted, a 36% reduction in Scope 1 and 2 emissions (which includes electricity
consumption) and a 23% reduction in Scope 3 emissions (e.g., fugitive emissions, commuting
and business travel).

The primary strategies to reduce Federal government GHG emissions is to reduce or eliminate
the consumption of fossil fuels by reducing demand, improving facility efficiencies, and using
alternative sources of energy. As such, E.O. 13693 establishes aggressive facility energy
reduction and sustainability goals for federal agencies to:

1. Reduce energy intensity (BTU per gross square feet) by 2.5% per year for a total of 25%
by 2025, compared to a 2015 baseline.
2. Design buildings, starting in 2020, to achieve net zero-energy by 2030.
3. Ensure that 15% of buildings meet Guiding Principles for Sustainable Federal Buildings
by 2025.

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 It also directs agencies to meet the following goals specific to renewable energy:

1. Ensure that at a minimum a percentage of building electric energy and thermal energy
shall be clean energy 1 as follows:

• Not less than 10% in fiscal years 2016 and 2017

• Not less than 13% in fiscal years 2018 and 2019
• Not less than 16% in fiscal years 2020 and 2021
• Not less than 20% in fiscal years 2022 and 2023
• Not less than 25% by fiscal year 2025 and each year thereafter.

2. Ensure that a percentage of the total amount of building electric energy consumed by the
agency is renewable electric energy as follows:

• Not less than 10% in fiscal years 2016 and 2017

• Not less than 15% in fiscal years 2018 and 2019
• Not less than 20% in fiscal years 2020 and 2021
• Not less than 25% in fiscal years 2022 and 2023
• Not less than 27.5% in fiscal year 2024
• Not less than 30% in fiscal year 2025 and each year thereafter.

3. As part of the renewable electric energy portion of the clean energy target, include:
• Agency-funded onsite renewable energy projects where renewable energy credits
(RECs) are retained
• Contracted onsite or off-site renewable energy projects where RECs are retained or
obtaining equal value replacement RECs
• Purchasing electricity and corresponding RECs
• Purchasing RECs.

4. Include in the alternative energy portion of the clean energy target:

• Onsite thermal energy where RECs are retained or obtaining equal value replacement
RECs
• Combined heat and power processes at federal facilities
• Fuel cell energy systems at federal facilities
• Energy from new small nuclear reactor technologies.
• Energy from new projects that actively capture and store carbon emissions associated
with energy generation
• Other alternative energy sources.

1
Clean energy comprises renewable electric energy as well as alternative energy such as renewable heat sources
(including biomass, solar thermal, geothermal, waste heat, and renewable combined heat and power [CHP]), non-
renewable CHP, small modular nuclear reactors (SMR), fuel cell energy systems, energy generation with active
capture and storage of carbon dioxide emissions (otherwise known as carbon capture and storage, or CCS), and
other alternative energy approaches that advance the policy set forth in section 1 and achieve the goals of section 2
of E.O. 13693

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 Implementation and consumption of renewable energy is a key strategy in achieving the
overarching federal energy and GHG emissions reduction goals. However, it must be
implemented hand-in-hand with other energy reduction strategies in order to be most effective.
Figure 2 depicts a common energy reduction hierarchy. Notice that renewable energy is not the
first step to reducing energy use and costs, but an important step after reducing loads (through
operational changes and improved facility management) and increasing energy efficiency
(through installation of more efficient building systems). A PV system installed on an inefficient
building is expensive and may pose a number of substantial risks. The PV system will need to be
larger to cover the wasted and inefficient use, which will significantly increase the size and cost
or the system, lengthen the payback period, and could potentially prevent the system from being
profitable. However, when PV solar systems are installed after a thorough energy analysis and
implementation of energy use reduction strategies, 2 the system can be sized accordingly to meet
renewable energy and other goals at the least cost.

Figure 2. A common energy reduction hierarchy

1.2.2 Other Renewable Energy Requirements
In June 2013, President Obama released The President’s Climate Action Plan. 3 The plan consists
of a number of executive actions based on three main pillars: 1) cut carbon pollution in America,
2) prepare the United States for the impacts of climate change, and 3) lead international efforts to
combat global climate change and prepare for its impacts. Under the Obama Administration,
federal agencies have reduced GHG emissions by more than 15%—the equivalent of taking 1.5
million cars permanently off of the road. To build on this record, the Obama Administration is
establishing a new renewable energy goal for the federal government: to consume 20% of its
electricity from renewable sources by 2020. This more than doubles the current goal of 7.5%.

2
Reclamation has conducted numerous sustainable building assessments and energy (EISA) evaluations that
analyze energy use and recommend energy conservation measures for improved facility performance. These reports
can be referenced at https://dosp/policyandadmin/SustainableBldgs/Pages/Main.aspx (sustainable buildings) and
https://teamsdrosp3.bor.doi.net/sustain/energy/eisa/Working%20Documents/Forms/AllItems.aspx (EISA
evaluations).
3
http://www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf, accessed May 05, 2015.

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 On June 02, 2014, the Environmental Protection Agency proposed new restrictions on carbon
pollution generated by coal-fired power plants in the United States in an effort to take real action
toward climate change. The final plan, entitled the Clean Power Plan, was unveiled by President
Obama on August 3, 2015, requires states to cut back on the carbon emissions from their power
plants by utilizing any of a number of different options, such as installing systems that operate on
renewable energy sources like wind and solar.

Federal agencies are required to achieve Guiding Principles for Sustainable Federal Buildings at
new construction, modernizations, and existing buildings greater than 5,000 gross square feet. A
key metric of the Guiding Principles is to implement lifecycle cost-effective renewable electric
energy and thermal energy projects onsite. As such, incorporation of renewable energy systems,
like facility-level solar PV discussed this Guidebook, makes progress towards compliance with
the Guiding Principles. Additionally, including a solar project in any design or retrofit helps
earn credits toward certification with third-party sustainable building rating systems, such as
Leadership in Energy and Environmental Design (LEED) 4 or Green Globes. 5 Typically, the
number of credits a facility can earn toward a rating is based on the percentage of building
energy cost that is offset by the system.

Other legal and regulatory requirements include utility requirements and historic building
considerations among others. These topics are covered in the section discussing specific site
analysis.

2 Solar Resource
Solar resource or the power of the sun striking the earth has been measured and mapped for the
surface earth with varying degrees of resolution and accuracy. These measurements are the basis
of estimating the energy production of a solar system and determining areas where high rates of
solar energy production can be achieved. Solar resource measurements are broken down and
reported in several different components since these different components can affect the energy
production of different types of solar energy systems in different ways. Below is a discussion of
solar resource components and other background material. Later in this guidebook these
concepts will be used to explain how they affect energy production of different types of solar
systems.

There are two basic components that are measured with respect to solar irradiance (power of the
sun: kW/m2) or insolation (energy over time: kWh/m2): direct normal irradiance (DNI) and
diffuse horizontal irradiance (DHI). DNI is the direct beam sun energy that comes directly from
the solar disc and is measured as kW/m2 on a plane that is always normal to the sun’s beam as it
traverses the sky during the day. DHI is the scattered irradiance of the sun which comes from all
directions equally and is measured as kW/m2 on a horizontal surface. One useful way to think
about this is if you are out on a very clear day and your shadow is sharply defined then most of
the sun’s irradiance is direct (DHI) or if you are out on a cloudy day and you cast no definable
shadow then the sun’s irradiance is primarily diffused (DNI).

4
http://www.usgbc.org/node/2612988?return=/credits, accessed September 01, 2016.
5
https://www.thegbi.org/green-globes-certification/how-to-certify/, accessed September 01, 2016.

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 Diffuse
Clouds, dust, etc.

DNI

Figure 3. Solar irradiance

Source: NREL

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 Figure 4. Hourly clear sky solar irradiance, Golden, Colorado

Figure 5. Hourly partly cloudy sky solar irradiance, Golden, Colorado

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 Combined DNI and DHI are the total sun’s energy. They are used for high level estimates of
solar energy for a site or are incorporated into weather files used with analysis programs for
estimates of energy production for specified solar energy systems. Solar resource maps and
mapping tools will usually include global horizontal insolation (GHI) and insolation on a
collector with a tilt at latitude. GHI is the total of the sun’s energy on a horizontal surface and is
usually reported as the average annual kWh/m2/day on that surface. GHI gives a good indication
of the overall solar resource at a location. Since solar collectors are typically tilted up from the
ground (i.e. not mounted horizontally) the metric tilt at latitude is often used to get a better idea
of the solar energy striking an actual collector. The tilt at latitude is usually reported as the
average annual kWh/m2/day of solar energy striking a collector that is tilted up toward the
equator at an angle that is equal to the latitude of the location. Tilt at latitude is used since this
collector orientation is usually close to producing the maximum annual energy from a system.
NREL’s Solar Prospector 6 is an interactive web map tool that shows these metrics and can give
a high level understanding to the solar potential of different locations quickly.

3 PV System Components
3.1 How PV Works
Solar PV technology converts energy from solar radiation directly into electricity. Solar PV cells
are the electricity-generating component of a solar energy system. When sunlight (photons)
strikes a PV cell, an electric current is produced by stimulating electrons (negative charges) in a
layer in the cell designed to give up electrons easily. The existing electric field in the solar cell
pulls these electrons to another layer. By connecting the cell to an external load, this current
(movement of charges) can then be used to power the load, e.g. light bulb.

- - -

Electron
-
(-)
(+)
Solar cell
- Load

- - -
Current flow

Figure 6. Generation of electricity from a PV cell

Source: NREL

PV cells are assembled into a PV panel or module. PV modules are then connected to create an
array. The modules are connected in series and then in parallel as needed to reach the specific
voltage and current requirements for the array. The direct current (DC) electricity generated by

6
http://maps.nrel.gov/prospector.

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 the array is then converted by an inverter to alternating current (AC) that can be consumed by
adjoining buildings and facilities or exported to the electricity grid. PV system size varies from
small residential (2 kilowatts (kW)-10 kW), commercial (100 kW-500 kW), to large utility scale
(10+ megawatts (MW)).

3.2 Major System Components

Figure 7. Ground mount array diagram

Source: NREL

Figure 8. Roof mount array diagram

Source: NREL

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 A typical PV system is made up of several key components:
• PV modules
• Inverter
• Balance-of-system (BOS) components
• Battery (optional and off grid system).

These, along with other PV system components, are discussed next.

3.2.1 PV Module
Module technologies are differentiated by the type of PV material used, resulting in a range of
conversion efficiencies from light energy to electrical energy. The module efficiency is a
measure of the percentage of solar energy converted into electricity.
A typical PV module is UL listed and tested to withstand certain wind, snow, and hail loads. PV
modules are rated in terms of maximum allowable pressure on the module surface. For example,
Figure 9 is an example of a PV panel rating for wind, snow, and hail loads that shows the
maximum pressure for snow load and wind load at 5,400 and 2,400 Pascal (Pa), respectively. PV
modules are not rated to specific wind speeds (mph) or snow loads (psf) because the racking
system might have a feature to adjust the tilt angle of the array, which would need to be taken
into account when calculating the maximum pressure on the modules.

Figure 9. PV panel rating for wind, snow, and hail loads

Two common PV technologies that have been widely used for facility- and utility-scale projects
are crystalline silicon and thin film. Other PV technologies use a variety of new materials
besides silicon, including solar inks using conventional printing press technologies, solar dyes,
and conductive plastics. The PV materials are less expensive than the silicon, but have lower
efficiency.

3.2.1.1 Crystalline Silicon

Traditional solar cells are made from silicon. Silicon is quite abundant and nontoxic. It builds on
a strong industry from both the supply (silicon industry) and product side. This technology has
been demonstrated as a consistent and high efficiency technology over 30 years in the field. The
performance degradation, a reduction in power generation due to long-term exposure, is under
1% per year. Silicon modules have typical power production warranties in the 25 to 30 year
range but can continue producing energy beyond this timeframe.

Typical overall efficiency of silicon solar modules is between 12% and 18%. However, some
manufacturers of mono-crystalline modules have demonstrated an overall efficiency over 21%.
This range of efficiencies represents significant variation among the crystalline silicon

10

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 technologies available. The technology is generally divided into mono- and multi-crystalline
technologies, which indicates the presence of grain-boundaries (i.e., multiple crystals) in the cell
materials and is controlled by raw material selection and manufacturing technique. Crystalline
silicon modules are widely used based on deployments worldwide and commonly used for the
facility-scale application. Figure 10 shows an example of crystalline solar modules

Figure 10. Crystalline solar modules

Source: NREL PIX 13823
3.2.1.2 Thin Film
Thin-film PV cells are made from amorphous silicon (a-Si) or non-silicon materials such as
cadmium telluride (CdTe) or copper indium gallium (di) selenide (CIGS). These cells use layers
of semiconductor materials only a few micrometers thick. Due to the unique nature of thin films,
some thin-film cells are constructed into flexible modules or building integrated modules such as
building integrated photovoltaic (BIPV). Other thin film modules are assembled into rigid
constructions that can be used in fixed tilt or, in some cases, tracking system configurations. Due
to the lower efficiency, thin film modules require more space than crystalline silicon modules at
the same capacity. Thin film modules are frequently used in large scale or utility scale projects
where space is not critically limited.

The efficiency of thin-film solar cells is generally lower than for crystalline cells. Current overall
efficiency of a thin-film module is between 6% to 8% for a-Si, 11% to 14% for CIGS, and 11%
to 14% for CdTe. Figure 11 shows thin-film solar modules.

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 Source: NREL PIX 14726 Source: NREL PIX 15160
Figure 11. Thin-film solar modules (left) and building integrated photovoltaics (right)
The cost of rigid thin-film solar modules is typically cheaper than crystalline modules. However,
the popularity of crystalline modules worldwide makes the cost gap between the technologies
smaller. Other thin-film application such as BIPV modules are used to replace conventional
building materials in parts of the building envelope. They are incorporated into a new
construction or a major renovation. It is important to note that BIPV prices are variable by
market and by application so pricing is something of a moving target. The BIPV modules
typically have a higher cost premium compared to the standard flat modules.

Industry standard warranties of both crystalline and thin-film PV modules typically guarantee
system performance of 80% of the rated power output for 25 years. After 25 years, they will
continue producing electricity at a lower performance level.

3.2.2 Inverter
Inverters convert DC electricity from the PV array into AC and can connect seamlessly to the
electricity grid. Inverter efficiencies can be as high as 98.5%.
Inverters also sense the utility power frequency and synchronize the PV-produced power to that
frequency. When utility power is not present, the inverter will stop producing AC power into the
grid that can be dangerous to utility workers that are trying to fix what they assume is a de-
energized distribution system. This safety feature is built into all grid-connected inverters in the
market. Electricity produced from the PV system may be fed to a step-up transformer to increase
the voltage to match the grid.
There are two primary types of inverters for grid-connected systems: string and microinverters.
Each type has strengths and weakness and may be recommended for different types of
installations.
String inverters are most common and typically range in size from 1.5 kW to 1,000 kW. These
inverters tend to be less expensive on a capacity basis, and typically have high efficiency and
lower operations and maintenance (O&M) costs. String inverters offer various sizes and
capacities to handle a large range of voltage output. For larger systems, string inverters are
combined in parallel to produce a single point of interconnection with the grid. Warranties
typically run between 5 and 10 years, with 10 years being the current industry standard. On
larger units, extended warranties up to 20 years are possible. Given that the expected life of the

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 PV modules is 25 to 30 years, an operator can expect to replace a string inverter at least one time
during the life of the PV system.
Microinverters are dedicated to the conversion of a single PV module’s power output. The AC
output from each module is connected in parallel to create the array. This technology is relatively
new to the market and in limited use in larger systems due to potential increase in O&M
associated with significantly increasing the number of inverters in a given array. Current
microinverters range in size between 175 W and 380 W. These inverters can be the most
expensive option per watt of capacity. Warranties range from 10 to 20 years. Small projects with
irregular modules and shading issues typically benefit from microinverters.
With string inverters, small amounts of shading on a solar module will significantly affect the
entire array production. If microinverters are used shading impacts only the shaded module.
Figure 12 shows a string and microinverter inverter.

Source: NREL PIX 07985 Source: Enphase

Figure 12. String inverter (left) and microinverter (right)
3.2.3 Balance-of-System Components
In addition to the solar modules and inverter, a solar PV system consists of other parts called
BOS components, which include:
• Mounting racks and hardware for the modules
• Wiring for electrical connections.
3.2.3.1 Mounting Systems
The structure holding the PV modules is referred to as the mounting system. There are two
primary applications of PV mounting systems: roof-mounted and ground-mounted systems. The
mounting system can be either directly anchored into the roof or ground or ballasted on the
surface without roof or ground penetration. For buildings, PV panels are mounted to the roof
pitch. For flat roofs, though the ideal tilt is equal to latitude, the panels are typically mounted at
10° to 15° tilt. Higher tilt may result in higher wind loads and self-shading. Mounting systems
should be selected and designed to withstand local wind loads, which range from 90 mph to 120
mph range for most areas or 130 mph or more for areas with hurricane potential. Depending on
the region, snow and ice loads should also be design considerations for the mounting system.

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 Source: NREL PIX 21403 Source: NREL PIX 04478

Figure 13. Anchored and ballasted PV mounting systems

Typical ground-mounted systems can also be categorized as fixed tilt or tracking. Fixed-tilt
mounting systems are characterized by modules installed at a set angle, typically based on site
latitude and wind conditions, to increase exposure to solar radiation throughout the year. Fixed-
tilt systems are the most common type. Fixed-tilt systems may have lower maintenance costs but
generate less energy (kWh) per unit power (kW) of capacity than tracking systems (Figure 15).

Tracking systems rotate the PV modules so they are following the sun as it moves across the sky.
The tracking systems increases energy output for roughly the same amount of space required for
the fixed tilt system. This could be a very good justification for going with a tracking system if
the project has some space restrictions. However, they also may increase maintenance and
equipment costs slightly. Single-axis tracking, in which PV is rotated on a single axis, can
increase energy output up to 25% or more. With dual-axis tracking, PV is able to directly face
the sun all day, potentially increasing output up to 35% or more.

The selection of mounting type is dependent on many factors including installation size,
electricity rates, government incentives, land constraints, latitude, and local weather.

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 Figure 14. PV system with fixed tilt
Source: NREL PIX 17394

Figure 15. PV system with single-axis trackers

Source: NREL PIX 00007

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 Figure 16. PV system with dual-axis trackers
Source: NREL PIX 04827

3.2.3.2 Wiring for Electrical Connections

Electrical connections, including wiring, disconnect switches, fuses, and breakers are required to
meet electrical code (e.g., NEC Article 690) for both safety and equipment protection. In most
traditional applications, wiring from (i) the arrays to inverters and (ii) inverters to point of
interconnection is generally run inside electrical conduits.

3.2.4 Battery
A fundamental characteristic of a PV system is that power is produced only while sunlight is
available. Batteries accumulate energy created by PV system and store it to be used at night or
when there is no other energy input. For a grid-tied system, where batteries are not inherently
required, they may be beneficially included for load matching or power conditioning. Unless
batteries are required, they should be avoided because they have high first cost and O&M cost. If
batteries are used they should designed to minimize life cycle cost (LCC) using a tool such as
HOMER. A vast majority of PV systems are connected to deep cycle lead-acid batteries.

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 Figure 17. PV system with battery pack
Source: Kosol Kiatreungwattana, NREL

3.2.5 PV System Monitoring

Monitoring PV systems can be essential for reliable functioning and maximum yield of a system.
It can be as simple as reading values such as produced AC power, daily kilowatt-hours, and
cumulative kilowatt-hours locally on an LCD display on the inverter. For more sophisticated
monitoring and control purposes, environmental data such as module temperature, ambient
temperature, solar radiation, and wind speed can be collected. Remote control and monitoring
can be performed by various remote connections and are often web based. Systems can send
alerts and status messages to the control center or user. Data can be stored in the inverter’s
memory or in external data loggers for further system analysis.

Weather stations are typically installed at large scale systems. Weather data such as solar
radiation and temperature can be used to predict energy production, enabling comparison of the
target and actual system output and performance and identification of under-performing arrays.
Operators may also use this data to identify required maintenance, shade on modules,
accumulated soiling on modules, etc. Monitoring system data can also be used for outreach and
education. This can be achieved with publicly available, online displays; wall-mounted systems;
or even smart phone applications.

4 Solar Energy System Siting: General Technical and

Site Specific Considerations
Siting and design of a solar energy system can quickly become a complex interplay of both
technical and economic variables, and actions required to comply with other federal law. In this
section the discussion will be limited to technical variables and specific site considerations.
Economic considerations and environmental and historic preservation requirements will be
discussed in a later section.

There are three basic types of siting or locations for facility-scale solar systems: 1) rooftop, 2)
ground mount, and 3) carports. There are many different variations and technologies for
implementation in these locations which is covered in the technology section.

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 There are many siting considerations when a specific site is being evaluated for a solar energy
system:
• Solar collector access to the sun (i.e. collector orientation and shading analysis)
• Available areas to locate a solar system at a specific site or facility (e.g. rooftop, ground
mount, and building integrated)
• Possible structural issues
• Compliance with National Environmental Policy Act (NEPA)
• Utility requirements
• Electrical interconnection
• Site master plan
• Compliance with the National Historic Preservation Act
• Computer network connectivity authority
• Climate considerations
• Vegetation considerations
• Auxiliary benefits.

4.1 Solar Collector Access to the Sun and Calculation of Available

Area
Solar energy at specific locations is highly variable and is affected by site locations (latitude),
hour of the day, day of the year, weather, elevation (i.e. thickness of the atmosphere), and the
orientation of the solar collector. As the sun traverses the sky each day and from season to
season, it is angled in relation to the solar collector changes and this incidence angle is a large
determinate in how much of the sun’s energy can be collected. If the sun’s beam is perpendicular
to a solar collector surface then the maximum solar energy can be collected but if the sun’s beam
is parallel to the collector surface then the collector cannot collect any of the beam energy. Note:
the diffuse component of solar energy comes from all directions equally (e.g. cloudy days)
therefore, sun angle does not affect the amount of diffuse energy that the collector collects.
Figure 18 illustrates the sun path.

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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 Figure 18. Sun path
There are a number of complex equations that enable exact calculation of solar incident angles
for a specific latitude that enable the calculation of solar energy on different solar collector
orientations throughout a year but conveniently there are easy-to-use tools that will calculate this
and other factors to estimate energy production . These tools will be discussed in a later section.

For specific sites, shading analysis is key to determining collector access to the sun’s energy. It is
important to perform a shading analysis to determine if any obstacles exist around a specific site
that might block the sun from striking a collector. These obstacles can include buildings (existing
and planned), topography (e.g. mountains), vegetation (in its present or future state), power lines,
and moveable assets (e.g. trucks, storage, or other temporary objects that may be placed in front
of a collector).

A quick analysis of objects that might shade a site can be done without any specialized tool by
following the process outlined in the solar screening checklist in Appendix A. There are also
several tools on the market that make this shading analysis process very easy. As one example,
Figure 19 shows a picture taken by a Solemetric SunEye that shows the sun path for the site
latitude overlaid on the specific location and the objects that that would shade that site. It also
calculates the percentage of annual solar access for the site for a specific collector orientation
taking into account the objects that will shade the site. At the site below the site is shaded only in
the early morning and late afternoon and has a calculated annual solar access of 96%.

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 Figure 19. SunEye shade analysis
The goal of the shading analysis is to define the available useable areas for a solar energy
system. Ideally, a site should have 100% annual solar access but this is not always the case so it
is recommended that a site has a minimum of 90% to 95% annual solar access. There are always
exceptions to this rule that depend on site goals and requirements, but in these circumstances
extra care needs to be taken in the system design and wiring to help ensure maximum energy
production.

Google Maps and Earth are useful tools in measuring and determining the areas of a site. There
are also a number of remote shading analysis tools such as Solar Census. Two primary areas that
can be used to locate a solar energy system are roof top and ground mount. If there is a building
at the site, the system may be located on the rooftop or possible integrated into the building
itself. If there is no building onsite or land area around the building, there are a number of
ground-mounted systems options. The solar system technologies section describes the different
technologies and mounting options that are available for these different locations.

4.2 Rooftop Solar Considerations

Rooftop systems need to take into account several different factors including:
• Roof age and condition
• Roof warranty
• Structural loading
• Fire safety guidelines
• Historic preservation.

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 The age and condition of the roofing material are two issues of concern when assessing
conditions for a rooftop system. Solar systems typically have a life of 25 to 30 years. If the roof
needs replaced during this time the system will most likely need to be removed and reinstalled.
This could add significantly to the LCC of the system and possibly make it uneconomical.

Roof warranty can also be an issue as there can be disputes on who is responsible for fixing
future roof problems, the solar system installer or roofing installer. It is recommended to contact
the company responsible for the roof warranty and discuss what is needed to keep the warranty
intact. If it is a new building, or if a new roof will be installed in conjunction with the solar
system, a good option may be that one company is responsible for both the solar system and roof
installation.

The structural loading of the roof is another key consideration. An assessment of the additional
structural load the roof can carry should be performed. The most common PV installation
method for flat roofs is a ballasted racking system. The typical weight of a ballasted PV system
is about 4 pounds per square foot but varies based on design wind speed, collector tilt, and
system design. If very little or no extra load can be placed on the existing roof structure (check
technology section for estimated weights of rooftop solar systems), then an estimation of what is
needed to increase the structural strength should be made. If roof structure enhancements are
needed, they can be completed separately or included in the scope of the solar system
installation. Structural enhancements can be expensive and may make solar uneconomical.

Rooftop systems may also need to comply with fire safety guidelines. Local fire authorities
should be contacted to determine requirements and confirm that none of the requirements would
make a system unfeasible. General Services Administration has a general purpose PV fire safety
guideline. 7

4.3 Ground Mount Solar Considerations

Ground-mounted systems offer a variety of mounting options, including fixed, parking shade
structures, and 1-axis or 2-axis tracking. Each option has its advantages and disadvantages.
Unless there is a specific mounting option that is required at the site, it is recommended that solar
installers be given the option of proposing solutions that best meet the stated needs of the
facility.

4.4 General Site Considerations

Site considerations for both roof- and ground-mounted systems include:
• Compliance with the National Environmental Policy Act (NEPA), National Historic
Preservation Act (NHPA), Endangered Species Act (ESA), and other environmental
laws
• Utility requirements
• BOS placement
• Site master plan
7
www.google.com/url?url=http://fpemag.com/_pdf/Fire_Safety_Guideline-
PV_System_Installations.pdf&rct=j&frm=1&q=&esrc=s&sa=U&ei=BZSgU66GJoK3yATSv4DICw&ved=0CBQQ
FjAA&usg=AFQjCNHEcw-h9vMtJF31NoHPaveuMYENGw

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 • Computer network connectivity authority
• Climate considerations
• Vegetation considerations.

4.4.1 Historic Preservation and Environmental Laws - General Considerations

Any type of system located on federal land or property, or one using federal funding or requiring
federal approval, may trigger environmental or historic preservation consideration and mitigation
under NEPA, NHPA, ESA, and other environmental laws. These laws should be addressed early
in the planning and design process to minimize the potential for redesign, scheduling delays, or
increased cost. The effort involved to comply with NEPA, NHPA, ESA and other environmental
laws greatly depends on where the project location and also on the project’s scale.

There are typically agency contacts that are responsible for compliance with each of these laws
for specific administrative or geographic areas or facilities. Consulting with these experts early
and often will ensure that they can provide timely input to help shape the decisions and the
directions regarding the site selection for the project and design criteria. This (and possibly other
information) will help avoid conflicts that could delay or even halt a project, and help define
information that will eventually go into the request for proposal (RFP) and ensure that the project
stays on track.

4.4.1.1 The NEPA process

The NEPA process begins with the agency environmental expert assessing the proposed system,
and the assessment produces one of the following three results:

1. Categorical exclusion (CE): A category of actions which do not individually or

cumulatively have a significant effect on the human environment. Solar projects meeting
the agency or bureau’s definition provided in its CE and whose impacts would not result
in significant impacts as described in Extraordinary Circumstances (43 CFR 46.215), are
excluded from further analysis under NEPA. A Reclamation CE, (516 Departmental
Manual 14.5) is appropriate to use for facility-scale solar projects, as long as the scope of
the project is consistent with the definition and terms of the CE and there are no
extraordinary circumstances (43 CFR 46.215).
2. Environmental assessment (EA): An EA involves a higher level of analysis and
documentation than a CE. It is used to identify the issues and the environmental effects of
a proposed action. An EA has two possible outcomes:

• Finding of no significant impact (FONSI): If an EA is required, the best outcome

is receipt of a FONSI. This process usually costs less than $500,000 and takes 6
months to 1.5 years.
• If the EA finds that environmental consequences could be significant, an
environmental impact statement (EIS) must be completed.
3. EIS: If the environmental expert finds that the project could have a significant
environmental impact from the beginning, an EIS is completed without completing an
EA first. This process can cost $1 to $5 million and take from 18 months to 5 years. If
successful, a record of decision is received and the project may proceed.

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 EAs and EISs have more details and usually apply to large scale and/or utility scale projects. All
levels may results in environmental commitments that need to be included in agreement or
contract documents and implemented during project construction and operation.

4.4.1.2 Endangered Species Act

The Endangered Species Act (ESA) 8 provides a program for the conservation of threatened and
endangered plants and animals and the habitats in which they are found. The lead federal
agencies for implementing ESA are the U.S. Fish and Wildlife Service (FWS) and the U.S.
National Oceanic and Atmospheric Administration (NOAA) Fisheries Service. The FWS
maintains a worldwide list of endangered species. Species include birds, insects, fish, reptiles,
mammals, crustaceans, flowers, grasses, and trees. The law requires federal agencies, in
consultation with FWS and/or the NOAA Fisheries Service, to ensure that actions they authorize,
fund, or carry out are not likely to jeopardize the continued existence of any listed species or
result in the destruction or adverse modification of designated critical habitat of such species.
The law also prohibits any action that causes a “taking” of any listed species of endangered fish
or wildlife. Likewise, import, export, interstate, and foreign commerce of listed species are all
generally prohibited.

4.4.1.3 National Historic Preservation Act Compliance

Installation of a solar PV system may have an adverse impact on historic properties. Many
Reclamation buildings and structures are historically significant. Section 106 of NHPA
requires federal agencies to consider the effects of a project on historic properties. Historic
properties are historically or culturally important resources that are listed on the National Register of
Historic Places, and may include:

• Prehistoric or historic period archeological sites or districts

• Historically significant buildings and structures or historic districts
• Historically significant landscapes
• Sites or locations that are of religious or cultural importance to Indian tribes.

Good planning integrates NHPA compliance into project design, as minimizing any impacts
typically involve site selection and design considerations. Adequate time and funding to
comply with NHPA are to be built into the project schedule and budget requests. The cultural
resources (CR) professional assigned to the office undertaking the project will have the lead
on NHPA compliance.

When beginning a solar PV project, the CR lead will assess if historic properties might be
affected by the proposed action, and then work with the solar team to seek ways to avoid or to
minimize adverse effects. The CR lead will also define and implement compliance actions, in
consultation with the solar team.

8
www.nmfs.noaa.gov/pr/laws/esa/

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 When installing a solar PV system, actions to minimize impacts often include:

• Placing solar PV panels on a roof face that is less visible to public view or on later
additions to historic buildings, or in an inconspicuous location on the property
• Minimizing removal or modification of original building materials or landscaping
• Selecting new materials that are compatible with a building or landscape’s historic
character and design
• Screening using plants or materials appropriate to the historic landscape.

If there are “adverse effects”, mitigation may consist of documentation of the property prior to
alteration, and/or presentation of site interpretive materials to the public. See Appendix J for
further general guidance.

4.4.1.4 ESA Considerations

Section 7 of the ESA requires federal agencies to consult with the FWS and/or National Marine
Fisheries Service (NMFS) for any action that “may affect” a federally listed endangered or
threatened species or its designated critical habitat. If it is determined a proposed federal action
will have “no affect” to a federally listed species or critical habitat, that determination is
documented in the administrative record for the project and no further ESA compliance is
necessary. If it is unknown or clearly a “may affect” situation, the consultation process can range
from an informal consultation where a federal agency is requesting FWS or NMFS concurrence
that its action “is not likely to adversely affect” a federally listed species (average 30 day
response time) to a formal consultation where the federal agency determines a proposed action
“may affect” a federally listed species and prepares a biological assessment and the FWS or
NMFS issues a biological opinion on whether the proposed action would jeopardized the
continued existence of a federally listed species or adversely modify critical habitat. This formal
consultation process can take months or longer to complete. It is important that environmental
compliance staff are engaged in the determination of affect to federally listed endangered and
threatened species as early in the planning process as possible to allow for compliance time-
frames as appropriate.

4.4.1.5 Other Environmental Laws

Compliance with other environmental laws, such as Migratory Bird Treaty Act and Clean Water
Act may be required, based on location, size, scope and disturbance resulting from the action. As
with all environmental considerations, consult with agency experts early in the process.

4.4.2 Utility Requirements

If a project includes PV, it also includes an electrical interconnection with the utility. The
interconnection agreement is made between the organization and the utility regardless of the
solar project developer’s role. It is important to communicate with the utility about the proposed
project early in the process. This ensures that all interconnection issues are taken into account
early on, and helps avoid unpleasant surprises after significant effort has been expended.
Depending on the utility and the local distribution system design, the project can be adversely
affected by expensive interconnection hardware and requirements. Some requirements can be
addressed during the design stage through equipment specifications, which incurs only a nominal
extra cost as compared to purchasing additional equipment.

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 Changes in the electricity tariff rate structure should also be explored and discussed with the
utility. Based on the system’s projected hourly and seasonal performance, a more optimal tariff
could be available that could potentially offset both energy charges and demand charges.
Although utilities are important partners in the process, they might not be enthusiastic about
reduced electrical consumption. Thousands of utilities operate in the United States with unique
rate structures and policies, so it is important for those planning a renewable energy project to
understand their rights as consumers and know what impact the solar system will have on future
utility billings. For example, a utility could impose a standby charge to cover the cost of
maintaining generation resources that are used when the solar energy system is not generating.
An agency should also determine whether it can sign a utility interconnection agreement that has
indemnification clauses.

The system owner and utility will develop an interconnection agreement that defines all the
specific requirements and terms of the interconnection. Information on interconnection standards
can be found at www.dsireusa.org/ (accessed September 01, 2016).

4.4.3 Balance-of-System Placement

The solar collectors are only part of the energy system and the equipment that connects the
collectors to the load or grid needs to be placed. If the system will be mounted on a building, is
there room for the inverters, electrical panels and other equipment in the existing mechanical
room or is there another location where they can be placed? If it will be a ground mount system,
are there any requirements on the BOS component placement? If there is more than one option,
then it is probably best to state this in the RFP and let the solar installer propose their best option.

4.4.4 Site Master Plan

If there is a master plan for the site, it should be reviewed at this stage. A solar energy project is
a long-term commitment, typically in place for 25 years or longer. When reviewing a master plan
from a 25-year perspective, things to consider include plans for undeveloped land that might be a
site for ground-mounted collectors or, in the case of rooftop arrays, determining if and when a
building is scheduled for retirement. Also important is whether any architectural plans include
aesthetic features that could preclude the installation of solar energy equipment. In such cases,
site managers have found that their project site options can be significantly limited.

4.4.5 Computer Network Connectivity Authority

Many renewable energy systems require automated monitoring and control. This is usually
accomplished by connecting the renewable energy system to a facility’s existing building-
monitoring system through a computer network connection. Some computer networks are
operated under contracts that have very specific requirements. These contracts can be restrictive,
allowing only network connection of specific devices, and sometimes even permitting only a
limited set of preapproved software and hardware. It is crucial that the parties controlling the
computer network be involved early in the process, because it is difficult and time-consuming to
acquire the authority to operate a system connected to the network. An example is the United
States Navy’s computer networks, which are operated by a contractor under the Navy/Marine
Corps Intranet contract. A renewable energy system that required a network connection was
installed, but because of the contract it could not be operated until required permissions were

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 obtained which was a long and difficult process. Another option to control the system is through
a cell phone based monitoring system that would bypass the hardwired network.

4.4.6 Climate Considerations

The meteorological conditions (e.g. rainfall, solar radiation, wind speed and direction,
temperature, and possibly corrosion such as salt mist) affect the PV system and system
performance and design, both individually and in combination. It is important to understand the
relevant meteorological conditions and their likely effects on the PV system performance.

4.4.6.1 Solar Resource Availability

Among the factors that are most important in evaluating whether a particular site is a good
candidate for a PV system is whether the site receives abundant sun most of the day. Federal,
state, or utility incentives may sufficiently improve the economics to enable PV systems in lower
resource locations.

Figure 20. Photovoltaic solar resource

Figure 20 shows the national solar PV resource potential for the United States. This map is
intended only to provide general guidance on available solar resource, and site-specific
conditions may vary. For this reason, developers typically conduct an individual site assessment
for purposes of evaluating and siting a solar system.

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 Site evaluations typically seek to identify portions of a given site that will receive sufficient
sunlight throughout the year. This onsite assessment is generally carried out using industry tools,
e.g. Sun Eye or Solar Pathfinder. See Section 4.1 for more details.

4.4.7 Vegetation Considerations

As mentioned in the shading analysis discussion, vegetation control and mitigation should be
taken into account when specifying a system. This includes grasses, bushes, trees and other
vegetation that may exist or grow in the future close to the site and shade the solar collectors.
Mitigation of this shading possibility may be part of the operation and maintenance of the system
(i.e. trimming and mowing) or specification of a ground mount system being a minimum height
above the ground that is above the height of local vegetation growth or specification of ground
treatment to eliminate vegetation around the system.

5 System Sizing and Energy Production Estimation

5.1 System Sizing
Sizing a solar energy system for a specific site includes many considerations to ensure a
successful system installation:
• Project goals
• Site load
• Energy storage(if need backup power or off-grid system)
• Utility requirements, incentives, and rate structures (if grid connected)
• Available area.

5.1.1 Project goals

Project goals will determine what the motivating factors are for the solar system installation and
this will drive the system size specification. Goals that might be considered include:

• Reducing fossil fuel consumption as much as possible

• Striving for a zero energy 9 facility
• maximizing production in the available space
• Buying the largest system possible with appropriated money
• Ensuring backup energy for critical facility functions,
• Off-grid operation for specific applications.

5.1.2 Site Load

Estimating or determining the site or application load is required for any project as this will be
the basis for determining system size or limitations on system size.

If the load is a grid connected facility, the site load should be easily determined from the energy
bill(s) for the facility. One year of bills would be the minimum required, but 3 to 5 years of bills

9
A zero energy building is “an energy-efficient building where, on a source energy basis, the actual annual
delivered energy is less than or equal to the onsite renewable exported energy.”

27

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 would be best in order to check for possible anomalies in power usage and/or trends in energy
use over time. Anomalies can include construction projects, mechanical failures, and special
events among other events. Increasing energy use can be due to more utilization of the facility,
increasing facility size, increasing equipment energy requirements, etc. When determining the
site load for design purposes these anomalies and energy use trends should be taken into account.
Also energy efficiency measures are typically cheaper per kWh saved than what it would cost to
produce the same kWh through PV. Therefore, it is recommended to consider and implement
energy efficiency measures first and reduce site load projections accordingly.

New facilities will typically include energy use estimates in the design documents and these can
be used to estimate site load.

Systems that will be designed to power a specific application (e.g. gate operation) may require
measurement/metering of the load over time or extrapolation of short term measurements to load
would be over time. If it will be an off-grid application, peak power consumption will need to be
determined in addition to energy use and specified period of autonomy (i.e. the period when the
solar cannot charge or add energy to the energy storage system).

5.1.2.1 Example calculations

Specific operation for off-grid:

Max energy (kWh) * # operations per day (#/day) * # days (days) / DC-AC conversion
efficiency (%) = Required energy storage capacity (kWh)

Where:
• Max energy for each operation (kWh), best if measured
• # days (days): number of day the system needs to operate without energy input to
batteries (typically 3 days but can be adjusted for climate)
• DC-AC conversion efficiency (%), converter efficiency to convert DC to AC power.

Backup power:

Load per day (kWh/day) * # days autonomy (days) / DC-AC conversion efficiency (%) =
Required energy storage capacity (kWh)

Where:
• Load per day (kWh/day): the load can be the whole facility or just critical loads that can
be powered separately by the system.
• # days autonomy (days): number of day the system needs to operate without energy input
to batteries (typically 3 days but can be adjusted for climate)
• DC-AC conversion efficiency (%): converter efficiency to convert DC power to AC
power need to run equipment.

For any energy storage systems the equations above are for useable capacity of the energy
storage system selected. The useable capacity of an energy storage system will depend on the
technology selected as some storage technologies will be damaged if they are completely

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 discharged. This means that the nameplate capacity may be larger than the calculated required
capacity.

5.1.3 Utility Requirements and Rate Structures

Utility interaction in the early stages of the project can be critical. Key issues are interconnection
requirements and limitations, net metering rules, any site specific issues, and rate structures.
Interconnection requirements can include any specialized equipment the utility might require and
any limitations on the size of the system the utility will allow to be connected to the grid. It is
important to note that there have been several instances where systems have been installed that
are larger than what the utility will interconnect leaving some of the installed system idle and
non-productive. Therefore, it is recommended to call the utility engineering department at the
beginning of the project to confirm there are no specific technical site limitations. Rate structures
will affect the business case and life cycle cost analysis (LCCA) calculation but can also affect
the sizing of the system (e.g. if there is net-metering, the system should probably not produce
more than the site energy use).

5.1.4 Available Area

Sizing of rooftop installations can be roughly estimated at about 100W/m2 of available area. But
it depends on the solar collector technology selected and the type of roof that will be utilized.

For example: For a roof with a reasonable tilt and azimuth, then the maximum array size would
be about 10 W per m2 per 1% efficiency of the module selected (e.g. the maximum system size
in 100 m2 with 15% efficiency modules would be 15 kW). PVWatts allows a user to draw the
available area of your system on the facility’s roof with various module efficiencies to calculate
what the maximum size could be. PVWatts is an online tool that aids in the design and
evaluation of solar PV systems. A flat roof needs spacing between rows of solar collectors,
which depends on the tilt and width of the collectors. If roof space is shaded or space is limited,
high efficiency panels are recommended. With the same capacity, high efficiency panels use less
space on the roof than the lower efficiency panels. In this case a 100 W/m2 is a reasonable
number for 12% efficient module but can increase with higher efficiency modules (e.g. the
National Park Service at Alcatraz Island could only use one building rooftop and to get the
required size system they needed to specify high efficiency module).

Ground mount systems typically require more area per kW installed than rooftop due to access
and boundary issues, and racking type. Table 1 gives estimates of the area needed per W of
capacity depending on technology or racking type. The given areas include the outer boundary of
the array (i.e. includes all area inside security fencing). Table 1 presents energy density by PV
panel technology and mounting type.

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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 Table 1. Energy density by panel and system for ground-mounted PV

Module Type System Type

Fixed-tilt Single-axis Tracking
2
Crystalline Silicon 2.9 – 5.5 DC-Watts/ft 2.4 – 4.5 DC-Watts/ft2
2
(31.2 – 59.2 DC Watts/m ) (25.8 – 48.4 DC Watts/m2)
Thin Film 1.7 – 2.9 DC-Watts/ft2 1.4 – 2.4 DC-Watts/ft2
2
(18.3 – 31.2 DC Watts/m ) (15.1 – 25.8 DC Watts/m2)
Source: “Best Practices for Siting Solar Photovoltaics on Municipal Solid Waste Landfills”, NREL report #
TP-7A30-52615, February 2013.

5.2 Energy Production Estimation

Energy production estimates for a PV system can be accomplished through several different
methods including simplified hand calculations to a number of software tools. Simplified
calculations and a couple free software tools will be covered below.

5.2.1 Software Tools for Estimating Energy Production

There are many software tools that will estimate energy production from a solar energy system
but two freeware tools are worthy of mention: PVWatts and System Advisor Model (SAM).
PVWatts is a web-based tool that requires only a few inputs. SAM is a downloadable freeware
that can perform a more detailed production and financial analysis of a system, if you have
specific system specifications.

5.2.1.1 PVWatts
PVWatts 10 is an online tool developed by NREL that aids in the design and evaluation of solar
PV systems. It starts with identifying the system location so it can retrieve solar resource data. It
will accept an address, zip code, or latitude-longitude coordinates. Once solar resource data has
been confirmed, basic system info is input. Figure 21 is a screenshot of PVWatts.

10
http://pvwatts.nrel.gov/.

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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 Figure 21. PVWatts
DC System Size (kW): Unless the system size is fixed, recommend 1 kW as input and scale
annual energy production.

Array Type: Options are fixed (open rack), which is typically ground mounted; fixed (roof
mount); 1-axis tracking and 2-axis tracking, typically ground mounted.

Azimuth: This is the orientation of the array (i.e. the direction it is facing). North=0, East=90,
South=180 and West-270.

System Losses: This is a factor that derates system production for a number of known and
possible system losses. The 14% losses default value should normally be used. Next to this input
is a button that opens a calculator that will allow recalculation of default setting for specific
systems. Tilt (deg) is the angle between the horizontal and the collector. The PVWatts default is
latitude of the location entered. Most systems will have a tilt between 10° and 25° unless it is a
tracking system. For 1-axis tacking, it is the tilt of the tracker axis from the horizontal (typically
0) and for 2-axis tracking this parameter is ignored. Figure 22 shows the system losses factor in
PVWatts.

These are all the inputs needed for a PVWatts energy production calculation. PVWatts will
calculate monthly and annual AC Energy production (kWh). Figure 22 shows the results for a 1
kW system as an example.

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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 Figure 22. PVWatts results for a 1 kW system

5.2.1.2 System Advisor Model

SAM uses either the PVWatts calculator or has a component-specific option to calculate system
energy production. If the specifics of the system are known or comparison of different
components is desired, SAM contains a library of system components and their characteristics as
well as detailed system inputs that can provide a more accurate estimate of energy production for
a specific system. The SAM website includes links to resources for learning the software.
Detailed information on SAM, video tutorials, and links to downloading the software are located
at https://sam.nrel.gov/ (accessed May 05, 2015). Figure 23 shows a summary of SAM outputs.

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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 Figure 23. Screen shot of the System Advisor Model outputs

5.2.2 Energy Production Estimation and Collector Orientation

Understanding the effect and importance of solar collector orientation on energy production can
be difficult to grasp. An optimum is to orient the collectors to get the maximum energy
production. Figure 24 shows the effect of collector orientation for Boulder, Colorado. On
average, the maximum energy production orientation is about 37° tilt and an azimuth of about 9°
east of south. The findings show that energy production does not degrade quickly as the
orientation is changed from the optimum. For this reason, other factors such as mounting
structure for wind loading, collector spacing, wiring, and other requirement that affect the
economics and technical requirements can become more important than optimal orientation.

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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 Figure 24. Effect of collector orientation
Source: Proceedings of Solar Forum 2001: Solar Energy: The Power to Choose April 21-25, 2001,
Washington, DC, Effects of Tilt and Azimuth on Annual Incident Solar Radiation for United States
Locations, Craig B. Christensen, Greg M. Barker.

6 Cost Overview
6.1 Cost Trends and General Rule of Thumb for PV Costing
The cost of a PV system depends on the system size and other factors such as geographic
location, mounting system, and type of PV module, among others. Based on significant cost
reductions seen in 2015, the average cost for non-residential, grid-tied systems have declined
from $3.95 per watt in Q1 2013 to $2.92 per watt in Q4 2015. With a growing market and an
increasing supply, further cost reduction is expected as market conditions evolve. Figure 25
shows the cost per watt of PV system from 2013 to 2015 for non-residential and utility scale
projects.

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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 2013-2015 Installed Price of Non-Residential and Utility Scale

$4.50
$3.95 $4.01
$4.00 $3.79 $3.70
$3.57
$3.44
$3.50 $3.26 $3.34 $3.23 $3.13
$2.92
$3.00 $2.69
$2.50
$2.14 $2.10 $2.04
$1.96
$/Wdc

$2.00 $1.85 $1.81 $1.88 $1.77

$1.72 $1.65
$1.53 $1.50
$1.50

$1.00

$0.50

$-
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
2013 2013 2013 2013 2014 2014 2014 2014 2015 2015 2015 2015

Non-residential Utility Scale

Figure 25. Average PV system cost from Q1 2013 to Q2 2015 11

Source: U.S. Solar Market Insight2015, Solar Energy Industries Association

6.2 Cost per Watt Breakdown

Historically, PV modules have represented approximately half of the system cost. Based on
significant price reductions due to a variety of market forces, the module cost represented about
30% of overall system costs as of a 2015 assessment. Costs for each component category as a
proportion of overall system cost are shown in Figure 26.

11
U.S. Solar Market Insight 2015 Year-end Review, Solar Energy Industries Association.

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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 Figure 26. Cost contributions of PV system components
Source: U.S. Solar Energy Market Insight Report 2015, Solar Energy Industries Association

6.3 Operation and Maintenance

The Federal Energy Management Program (FEMP) has tabulated O&M costs for grid-tied
distributed generation scale systems varying from $21 +/- $20 /kW/year for systems < 10kW to
$19 +/-$10 /kW/year for large systems >1 MW. 12

PV operation and maintenance includes the following areas:

• Monitoring: Monitor system and analyze data to remain informed on system status and
performance. Includes comparing results of system monitoring to benchmark expectation.

• Administration of Operations: Ensure effective implementation and control of O&M

activities including archival of as-built drawings, equipment inventories, owners and
operating manuals, and warranties. Also keep records of performance and O&M
measures,

• Directions for the Performance of Work: Specify the rules and provisions to ensure that
maintenance is performed safely and efficiently

• Operator Knowledge, Protocols, and Documentation: Ensure that operator knowledge,

training, and performance will support safe and reliable system operation.

12
www.nrel.gov/docs/fy15osti/63235.pdf.

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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 • Preventative Maintenance: Schedule preventive maintenance to conform to the
manufacturer recommendations as required by the equipment warranties.

• Corrective Maintenance: Repair damage or replace failed components. Less urgent

corrective maintenance tasks can be combined with scheduled, preventative maintenance
tasks.

Maintenance on PV systems is typically low relative to other forms of energy generation. Solar
PV systems to maintain include the solar panels, mounting systems, inverter, and wiring and
connections. This assumes a system without batteries. The following activities should be
performed on a routine basis and approximate timeframes are provided. The environment,
location, and system design are other considerations when determining how often to perform
routine maintenance. Always refer to any operating manuals received after installation for
manufacturer’s recommendations.

Solar Panels:

• Perform a visual inspection for chips, cracks, delamination, and water leaks
approximately every six months.

• Remove dirt and dust with water and/or a sponge depending on the amount of fouling. Do
not use brushes, any types of solvents, abrasives, or harsh detergents.

Mounting System:

• Perform a visual inspection for rusted bolts or connections annually.

• Ensure frame and modules are secure annually.

Inverter:

• Clean (vacuum) dirt and dust from heat rejection fins annually.

Wiring and connections:

• Perform a visual inspection for cracks, corrosion, and deterioration in wiring insulation
and conduit annually.

Service descriptions for preventative maintenance and corrective maintenance can be found in
Appendix G and H.

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 7 Economic Analysis and Business Structures
7.1 Economic Analysis
The intent of Reclamation’s economics technical memorandum No. EC-2013-02, The Basics of
Lifecycle Cost Analyses Supporting Reclamation’s Sustainable Energy Goals, is to develop the
economic analysis for a solar energy system. Calculation of LCCA, savings-to-investment ratio
(SIR) and modified internal rate of return (MIRR) are all mandated by 10 CFR 436A for analysis
of energy projects. Reclamation’s guide 13 provides step-by-step instructions on how to perform
the necessary calculations and gives sources for finding and developing the required input data.
The discussion below is a summary that will support and assist with the development of these
analyses as defined by the Reclamation’s guide.

7.1.1 Life Cycle Cost Analysis

An LCCA is the primary tool mandated by legislation and executive orders for economic
analysis of federal investments in energy and water conservation and renewable energy in federal
buildings. An understanding of LCCA will assist Reclamation staff in achieving the goals for
non-hydroelectric renewable energy at Reclamation facilities. For more information, see
Appendix I: The Basics of Lifecycle Cost Analyses Supporting Reclamation’s Sustainable Energy
Goals. Another source of general cost data is The Open PV Project 14 which can be searched by
state, type of system, and size of system. The U.S. Department of Energy also has a website to
help with energy analysis with links to reports and tools on solar cost information that can be
found at: www1.eere.energy.gov/analysis/ (accessed September 01, 2016).
Generally, the cost for a solar energy system at a federal facility may be more than the cost of a
commercial system due to Federal Acquisition Regulation (FAR) and wage requirements. Rule-
of-thumb installed cost, operation and maintenance cost can also be found at
www.nrel.gov/analysis/tech_lcoe_re_cost_est.html (accessed September 01, 2016). Capital
replacement costs for a PV system can be assumed to be an inverter replacement in year 15 at a
cost of around $0.15/W.
7.1.2 Savings-to-Investment Ratio
SIR is a ratio of the present value of net savings to the present value of net cost the solar energy
system. The net savings includes energy cost savings and any O&M cost savings the system will
produce. The net cost includes the initial investment and replacement cost less salvage value.

7.1.3 Modified Internal Rate of Return

MIRR is a modification of the internal rate of return (IRR). The IRR is the discount rate that
would make the net present value (NPV) of a project equal to zero but assumes that positive cash
flows from the project can be reinvested at the same rate as the IRR. MIRR is different from IRR
in that the reinvestment rate is set equal to the cost of capital or financing rate (i.e. not the
calculated IRR).

13
https://www.usbr.gov/power/Reclamation%20Sustainable%20Energy%20Strategy%20.pdf.
14
https://openpv.nrel.gov/.

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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 7.2 Factors Affecting Economic Analysis Inputs
• Utility tariff structure
• Available incentives
• Ownership model.

7.2.1 Utility Tariff Structures

Understanding the utility tariff structures is required to be able to calculate actual possible energy
cost savings. Some utilities may require the facility to change to a different rate structure if it
installs a solar energy system that may or may not be beneficial economically. It is important to
know what rate structures would be available to the facility if it a solar energy system is
installed, so a correct economic analysis can be made.

Three typical rate structures are flat-rate, time of use (TOU) and block rates. Flat rate is where
each kWh is the same price no matter how many kWh are consumed. TOU rates are where the
cost of each kWh depends on the time of day and day of the week when the kWh is consumed.
Block rates have a different cost per kWh depending on how many kWh are consumed in that
period (e.g. the first 500 kWh consumed during the billing period would be one price and the
next 1,000 kWh would be another price, and so on).

The utility may also pay a different price for kWh fed back into the grid than for kWh consumed
from the grid. In addition to energy charges the tariff structure may include demand charges.
Demand charges are based on the peak power needed by the facility during a specified amount of
time and are billed in $/kW. Solar energy systems typically provide minimal demand savings due
to clouds but may help reduce demand charges since solar produces energy at the same time as
typical peak power consumption. SAM software has the capability to analyzing complex rate
structures that depend on the time of day the solar energy is producing energy (e.g. TOU) and
demand charges.

Net metering policy should be fully understood. Net metering means that excess kWh produced
by a solar energy system and put into the grid will be used to offset energy consumed by the
facility from the grid at a later time (i.e. the grid is used as a battery for the solar energy system).
There are several key criteria that can vary including system capacity limits, eligible customer
and system types, how any excess generation is treated at the end of a billing period, and who
owns the RECs. Information on net metering policy can be found at: http://www.dsireusa.org/
(accessed September 01, 2016).

A feed-in-tariff (FIT) could be another option for selling and valuing the energy production from
a solar energy system. FITs in general are long-term contracts (10 to 20 years) with the utility to
sell the energy produced by the solar energy system. Policy and rules can vary widely where
FITs are available. The DSIRE website has first level information on FITs by state but the
serving utility would be able to confirm availability and terms.

7.2.2 Available Incentives

Incentives can reduce the cost of solar energy systems. The DSIRE website has first level
information on solar incentives but the availability and terms would need to be confirmed by the
entity offering the incentive (e.g. state, local government, utility, or other).

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 7.2.3 Ownership Models
There are two basic ownership models available for a Reclamation facility solar energy system:
1) federal funded and owned or 2) owned by a third-party. If the business case for the solar
system meets agency criteria and funds are available to purchase the system, then a federal
owned system is an option. If federal funds are not available for the solar energy system, there
are several contracting options to that may be used.

The primary issue with procuring a solar energy without agency funding is a need for long-term
contracts to make the project economically viable. Solar energy system cost is primarily initial
installation cost with low operating cost (e.g. no fuel cost) and the system produces energy for 20
years or more. Therefore, contracts with the third-party owner of the system need to be long-term
(15 to 20 years) to make the annual or kWh cost of energy from the system competitive with
alternatives. Due to restrictions on contract lengths that federal agencies can enter into (10
years), there are only a few contracting authorities that allow contract of the needed length.
FEMP supports federal agencies identify, obtain, and implement project funding for energy
projects and information on this assistance can be found at http://energy.gov/eere/femp/project-
funding (accessed September 01, 2016). Also, detailed descriptions and step-by-step guidance
for these contracting options are given in Procuring Solar Energy: A Guide for Federal Facility
Decision Makers. 15

Below is a brief description of each option with some updates. Available options include:
• Power purchase agreement
• Energy savings performance contract
• Utility energy services contract.

7.2.3.1 Power Purchase Agreements

Power purchase agreements (PPA) have been used to finance solar projects since 2003 and are
now driving most commercial solar installations. Under a PPA, a private entity (typically a group
consisting of developers, construction companies, and finance companies) installs, owns,
operates, and maintains customer-sited (behind the meter) solar energy generation equipment.
The site purchases electricity through a long-term contract with specified energy prices. Payment
is based on actual energy (kilowatt-hours or therms) generated from the solar equipment and
consumed by the site. PPAs typically require long-term contracts to make the offered price of
energy competitive. To address the contract length limitation, federal agencies are exploring
methods that are available under existing federal laws and regulations, and also are making other
contractual issue improvements. One option is if the facility is in the Western Area Power
Administration’s (Western) territory, Western can use its long-term contracting authority to
purchase renewable energy from a renewable energy system on a federal site on an agency’s
behalf.

7.2.3.2 Energy Savings Performance Contracts

Energy savings performance contracts (ESPC) have a long history of use in the federal sector
and have primarily been used for energy efficiency projects. They are increasingly being seen,

15
www1.eere.energy.gov/solar/pdfs/47854.pdf, accessed September 01, 2016.

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 however, as a long-term financing method for solar projects. An ESPC is a guaranteed savings
contracting mechanism that requires no up-front cost. An energy services company (ESCO)
incurs the cost of implementing a range of energy conservation measures (ECM) which can
include solar and is paid from the energy, water, and operations savings resulting from these
ECMs. The ESCO and the agency negotiate to decide who maintains the ECMs. Payments to the
contractor cannot exceed savings in any one year.

There are a number of ways a solar project can be implemented under the ESPC contracting
authority. Most ESPC solar projects to date have been done in combination with energy
efficiency measures where the complete project bundle (i.e. solar and energy efficiency) meets
the criteria for an ESPC (i.e. annual payments to the contractor cannot exceed savings). For
smaller ESPC projects FEMP has implemented ESPC ENABLE that provides a streamlined
process to implement specific ECMs in six months or less. The allowed ECMs include solar PV.
The ENABLE 16 program utilizes the General Services Administration schedule with pre-
approved vendors and pre-negotiated pricing. Another option that is being considered is to allow
a PPA to be an ECM under an ESPC contract (i.e. a PPA using the long-term contract authority
of an ESPC). This option is known as an ESPC RECM.

7.2.3.3 Utility Energy Services Contract

Utility energy services contracts (UESC), like ESPCs, have a history of use in the federal sector
primarily for energy efficiency projects. These contracts are also being seen as a method of long-
term financing, with the added benefit of usually being a sole source contract. A UESC is an
agreement that allows a serving utility to provide an agency with comprehensive energy- and
water-efficiency improvements and demand-reduction services. The utility could partner with an
ESCO to provide the installation, but the contract is between the federal agency and the utility.
This contracting mechanism primarily is for bundled energy-efficiency and renewable energy
projects, and typically is not used for standalone renewable energy projects. The steps in the
UESC process are well defined, but different utilities might describe them differently.

8 Project Execution
This section summarizes the steps needed to execute a specific site solar procurement. More
detailed information on these steps is located in Procuring Solar Energy: A Guide for Federal
Facility Decision Makers. 17 Though this section largely considers single site installations,
agencies should look for innovative ways to aggregate procurements as much as possible to
benefit from economies of scale and to reduce transaction costs.
Project Steps:

Step 1. Identify needs and goals

Step 2. Assemble an onsite team

Step 3. Evaluate candidate solar energy sites

16
http://energy.gov/eere/femp/espc-enable, accessed September 01, 2016.
17
https://www1.eere.energy.gov/solar/pdfs/47854.pdf, accessed May 05, 2015.

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 Step 4. Consider project requirements and recommendations
Step 5. Make a financing and contracting decision
Step 6. Follow the process for the financing and contracting method selected.

8.1 Identify needs and goals

Several common reasons for considering a solar project include:
• Agency must meet renewable energy targets
• Appropriations are available for improving a facility
• Project is a good way to meet a site’s needs—depending on site conditions, there can be
many smart reasons to implement a solar project including off-grid or backup power for
remote locations
• Project can provide energy cost savings
• Project can reduce future energy cost volatility and uncertainty

• Project will earn credits toward LEED certification.

The reasons for considering a solar project help to define the needs and goals that the project will
address. Needs and goals comprise the vision, the touchstone, and the principles that guide the
process of setting priorities, creating decision criteria, and making decisions. Solar should be part
of a broader vision of whole systems design for buildings and sites. Potential goals or criteria
include the following:
• Maximize onsite solar energy production (particularly within a restricted budget)
• Maximize the return on investment
• Meet a minimum annual solar energy production target
• Maximize GHG reductions.
Goals could adjust or change as the project develops, but they always should be at the forefront
during the decision-making process.

8.2 Assemble an onsite team

At this point, a solar project team should be identified. The team is important not only for getting
the work done, but also for making sure that all issues are considered. Even small oversights can
be costly in terms of dollars and time, and can even result in a failure to accomplish project
goals.

One of the most important features of the team should be its alignment with the project’s goals.
Another important feature of the team is to ensure it includes or involves persons who can
address other legal requirements, such as NEPA, NHPA, and ESA. The project goals can adjust
with team input and healthy debate on project questions. Step 4 - Consider project requirements

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 and recommendations can help when considering the makeup of the team. It outlines the diverse
considerations that feed into successful project completion. It is important to recognize that it
takes a diverse group of people with a wide range of skills to bring a project to fruition.

8.3 Evaluate candidate solar energy sites

Detailed information is needed to evaluate specific sites for solar energy installations. These
findings may be available from an agency-wide solar screening if your agency has one, or they
may need to be compiled by the solar project team.

There are two recommended levels of solar site evaluation:

1. A project solar screening, which is a high-level, preliminary analysis used to determine a
site’s likely viability.
2. A project solar feasibility study, which is a more rigorous engineering and economic
analysis to define specific system design considerations for use in requests for proposals
and/or scope of work development. This would also include collecting data to determine
NHPA and ESA compliance requirements.
For projects that propose to use alternative financing, a project solar screening is sufficient to
proceed. For agency funded projects, a solar feasibility study is recommended.

8.4 Consider project requirements and recommendations

If, at this point, the solar screening demonstrated that the project is viable, the following should
be considered:
• Utility interaction
• NEPA, NHPA, ESA and other environmental compliance
• Site master plan review
• E.O. 13693 and other renewable energy goal requirements
• Project incentives
• Historic building issues
• Computer network connectivity authority.

8.5 Make a financing and contracting decision

Unless funding is designated for the project (i.e., the agency will fund the project), this can be a
complex decision. If no direct funding is available, financing options must be considered. Before
choosing an available financing option, review the options. FEMP maintains a website and offers
webinars and workshops to educate participants on the different financing options available. The
FEMP financing information can be found at http://energy.gov/eere/femp/project-funding
(accessed September 01, 2016). The FEMP training information is available at
http://energy.gov/eere/femp/training (accessed September 01, 2016).

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 8.6 Follow the process for the financing and contracting method
selected
The solar project shall consult on a process for financing and contracting with the Acquisition
and Assistance Management Division that has overall responsibility for Reclamation's
acquisition and financial assistance policy, acquisition and financial assistance operations, and
property programs.

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 Appendix A. Self-Guided Solar Screening
A preliminary solar energy site screening provides a rough estimate of the solar resource, energy
production, and cost of a PV system. It also provides information for a go- or no-go decision to
proceed further in the procurement process. A more thorough solar energy site screening may be
needed later to better quantify the energy production and costs before proceeding further.

A summary sheet is included at the end of this section to record the data and observations. The
summary sheet, along with any drawings or photographs, is needed for the next steps in
procuring a PV system. Shooting photographs of the site and equipment is critical, as they allow
others to confirm the preliminary estimate or make recommendations without visiting the site.

Solar Site Screening

Prior to a Site Visit
Preview the site using PVWatts (http://pvwatts.nrel.gov/) or Google Earth
(http://earth.google.com) to identify possible land or roof areas for a PV system.

• Identify roof areas with flat or equator-facing surfaces (e.g., south in the northern
hemisphere) with little or no equipment on the roof
• Identify large, open land areas
• Print an overhead map of the site and mark these potential land and roof areas on the map
for ease of location during site visit.
Use PVWATTS (http://pvwatts.nrel.gov/). Calculate, and print out, the energy production for a 1
kW PV system tilted at 10 degrees, and use the defaults for all other inputs. The monthly and
yearly energy outputs for a 1 kW system are useful numbers for scaling to larger systems. For
example, a 55 kW PV system produces 55 times the energy of a 1 kW PV system.

When on Site
Access the roof or land area being considered for PV systems. Note the tilt angle and orientation
of the equator-facing or flat roof area. Also note the type, condition, and age of the roof. For land
area note the approximate grade and orientation of the land area. Take photographs.

The objective now is to determine the area of the site for a potential solar system as this will
allow an estimation of the potential system size. The site needs to be very clear of objects that
could cast shadows on the proposed site. While standing on the proposed site, use your thumb
and fist to estimate the angle of the object from the horizon to the top of the object. A sideways
thumb held at arm’s length is about 2 degrees from the bottom to the top of the thumb. A fist
held in front of your body is about 10 degrees from the bottom (little finger) to the top (pointer
finger) of the fist (see www.vendian.org/mncharity/dir3/bodyruler_angle/). Objects that are less
than 20 degrees in height above the site, that are skinny (e.g., power poles), or that can be
removed should be ignored for this preliminary estimate. For objects that are on the site, make
height-angle measurements close to the roof or ground where the collectors will be placed.

Determine the square footage of the site that is not shaded by objects, as determined above. For a
preliminary estimate, the distances could be paced off. If available, use a measuring device such

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 as a range finder or a rolling wheel tape measure. Take several photographs that could be used to
make a panoramic photograph.

If a roof area is being considered, ask the people on site if the roof leaks, when it was last
replaced or repaired, or if they have any concerns about it. Note their answers. Take photographs
of the roof and the underside from inside the building if possible. Ask about the roof age and
construction and whether any drawings are available. Make a copy or take a photo of any
drawings.

Photovoltaic Specific Assessment

Identify the nearest location for housing the inverters. It is best if this location is shaded or
enclosed. Small inverters (6 kW or less) can hang on a wall. Larger inverters (greater than 6 kW)
are placed on the ground or floor. Note the distance from the proposed PV system location to the
inverter bank. Take photographs.

Identify the nearest electrical panel and record the location and distance from the inverter bank to
the electrical panel, voltage at the electric panel (V), the number of phases (1 or 3), capacity of
the main breaker (amps), and the capacity of the panel (amps). Take photographs of the
equipment, including the circuit breakers.

Energy Production Estimate

Estimate the size of the PV system by multiplying the proposed site area (ft2) times 9.3 W/ft2.
This corresponds to a fairly typical 14% efficient crystalline PV module. This preliminary solar
energy site assessment is for no, or relatively few, solar obstructions. If the solar obstructions
become numerous or complicated, then a more detailed solar energy site assessment should be
made.

PVWatts can also be used for estimating PV capacity and electricity production of a proposed
site area. A user can use the map tool to roughly approximate the size based on the roof or
ground area available for the array at the system location. The map tool calculates a value for the
DC nameplate size and populates the System Size input with the value.

Site Energy Requirements

Prior to a site visit, or while on site, determine the annual energy usage from the utility bills. Ask
the site personnel if any energy efficiency changes will be made or if electrical load increases are
anticipated.

Determine the annual electrical energy consumption for the building or site. Compare this
number to the estimated energy production from a PV system. In most locations there is little
economic sense to produce more energy than is consumed. If needed, reduce the PV system size
to just meet the annual electrical energy usage.

Divide the estimated PV system production by the annual electrical energy usage. This is the
percentage of annual energy supplied by the PV system.

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 Cost Estimate
A conservative price estimate for a fully installed PV system is $3,500 to $4,500 per kW of PV.
Large PV systems (greater than 100 kW) or PV systems on sites with uncomplicated site access
or conditions have been installed for less money. This price range is for a simple grid connected
PV system without batteries. Systems with batteries can easily double the installed price.

Incentives
Available incentives for solar projects can be critical to the economic feasibility of a prospective
project. Look up and list incentives that apply to the project. The DSIRE Web site lists most
incentives available for solar projects from federal, state, local, and utility sources
(www.dsireusa.org, accessed September 01, 2016).

Go- or No-go Decision

The information compiled here will form the basis of the economics that will be used for a
decision to explore the feasibility of the project further.

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 Appendix B. Summary of Preliminary Solar Energy Site
Screening for Photovoltaics

Name of Location: ______________________________________________________________

Latitude and longitude, or ZIP code: ________________________________________________
Assessment performed by: (include contact information)________________________________
______________________________________________________________________________

Date of Assessment: _____________________________________________________________

Area (ft2)

Maximum PV system size (kW)

Estimated annual PV system energy

production (kWh/yr)(from PV WATTS)

Building or site annual energy consumption

(kWh/yr)

Percent solar contribution(production

divided by consumption [%])

Distance from PV system to inverter (ft2)

Electrical service (voltage and # of phases)

Total installed price estimate ($)

Present price of energy ($/kWh)

Estimated annual energy savings ($/yr)

(estimated annual energy production
multiplied by present price of energy)

Possible Site Issues

Historic building issues? _______________________________________________________

Structural issues (if rooftop)? ____________________________________________________

Roof age and condition? _______________________________________________________

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 Planned replacement?__________________________________________________________

List available incentives for solar projects on the site:_________________________________

____________________________________________________________________________

Comments (use another page if necessary):______________________________________

____________________________________________________________________________

Attach drawings, photographs and printouts.

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 Appendix C. Solar Screening Evaluation Checklist
This is a checklist to review the adequacy and quality of a given solar screening and to determine
if a more detailed screening needs to be done. If an applicable element is missing from the
screening, it is recommended a more detailed solar screening for the site be obtained.

The checklist is in two parts. The first part is for solar screenings and pertains to financing
mechanisms other than agency funded. The second part is for solar feasibility studies and
includes recommended information in addition to the solar screening.

Solar Screening minimum recommended information (items 1 – 5)

1. Confirm shading analysis, available square footage and preliminary size estimate:
 Satellite map view or use of an accurate aerial tool to analyze the potential shading
impacts of neighboring buildings, rooftop protrusions, parapets, or vegetation that could block
sunlight from a potential solar array and relate these impacts to the available roof or ground
area.
 Satellite or accurate aerial tool measurement of the available square footage or acres
 Preliminary estimate of the system size

2. Confirm annual energy production per unit of capacity:

 Electricity production estimates
__________ (kWh/yr/kW installed)

(available online tools: PVWATTS).

Inputs for this level of analysis are as follows (unless site conditions preclude, i.e., a steep
pitch roof that does not face the equator):
 1 kW system size
 10 degrees from horizontal-tilt (if you have a pitched roof, enter actual pitch)
 Local location or nearest location option with similar sun exposure
 14% system losses
 Azimuth (compass orientation—select 180 degrees or 0 degrees so array faces equator or,
for a pitched roof, enter the direction that the roof faces)
 Solar thermal (available online tool: RetScreen www.retscreen.net/ang/home.php)
 Solar ventilation preheat (available online tool: RetScreen)
 Solar pool heating (available online tool: RetScreen)

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 3. Confirm economic analysis:
 Confirm local energy rates
__________ ($/kWh or $/therm)
 Annual savings
__________ ($/yr/ kW installed)
 Any available incentives?
__________ ($/W or $/yr/W)
(i.e. rebates, local Renewable Energy Credits market, other).
Check DSIRE: www.dsireusa.org
 Any extraordinary project specific costs?

__________ ($/W)
Confirm that structural, electrical inter-connection, and equipment location issues have been
investigated and any additional costs related to these have been estimated.
 Estimated System cost

__________ ($/W)
 Appropriate economic metric for your decision-making process.
__________ (SIR, NPV, LCC, other)
(Solar Advisor Model is available online and does some financial analysis.)
NOTE: In general, the estimated cost should not exceed $4 per watt except in special
circumstances.

4. If proposed system is rooftop:

 Age of roof

__________ (yrs)
 Condition of roof
__________ (yrs of expected remaining life)
 Roof warranty
__________ (yrs remaining)
 Estimated structural capacity available for solar system
__________ (lbs/ft2)
 Estimated maximum weight of solar system

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 __________ (lbs/ft2)
5. Confirm other considerations have been addressed:
 Historic building issues (is the proposed system on a historic building or in a historic
district?)
 National Environmental Policy Act (NEPA) issues.
Solar feasibility study minimum recommended information in addition to the Solar Screening
information (items 1-9)
6. Confirm recommended size
 Is the recommended size in assessment reasonable and is there opportunity for a larger
system?
__________ (kW or area of collectors)
In PVWatts is a Web tool that uses aerial maps and a draw feature to estimate PV system size
on a site. See http://pvwatts.nrel.gov/.
7. Confirm shading analysis (recommendations for report)
 Detailed shading analysis with solar collector exclusion areas marked on the plan view of
the site adjacent shading obstructions. Exclusion areas should be indicated to the east, west,
and toward the equator (if in the northern hemisphere- to the south) of any shading
obstruction.
 Unless the array is installed with zero degrees tilt (horizontal), need to see some space
between rows in the array layout to prevent rows of PV shading each other.

8. Confirm investigation into interconnection issues:

 Requirements to get utility approval for interconnection (estimated costs if special
equipment is required)
 Recommended interconnection point
 Confirmation of space for system electrical equipment
9. Confirm annual energy production for site-specific recommended system
 Electricity production estimates
__________ (kWh/yr)
(available online tools: PVWatts).
Inputs are:
 __________ (kW) system size
 __________ (degrees from horizontal) tilt

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  __________ Location
 __________ Derating factor (default is 0.77)
 __________ (degrees-compass orientation) Azimuth
 Solar thermal (available online tool: RetScreen)
 Solar ventilation preheat (available online tool: RetScreen)

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 Appendix D. PV Project Design Evaluation Checklist
This checklist has been created to assist you in the design phase of the system during the 25%,
50%, and final review stages.

Site Layout
 __________ (degrees) tilt
 __________ (degree) azimuth
 __________ (kW or MW) system size
 Engineer’s stamp on PV array mounting design for wind loading
 Confirm shading analysis has been done and site layout conforms to it.

Rooftop system:
 Engineer’s stamp on roof structural weight carrying capacity for solar system

 Confirm weight of system is within carrying capacity of roof (lbs/sq ft)

 What type of roof penetrations, if any, and confirm construction detail to weatherproof
penetrations
 Check PV layout compliance with fire specifications. (Fire Safety Guideline for
Photovoltaic System Installations: www.fpemag.com/_pdf/Fire_Safety_Guideline-
PV_System_Installations.pdf)

Ground-mount system:
 __________ (ft) Height of lower edge of collector to ground. Usually like to see a
minimum of 2 feet between the lower edge of the PV modules and the ground. This can be
location specific (examples):
i. In desert areas where vegetation does not grow tall and could possibly shade the array,
the array could be closer to the ground.
ii. In areas of high snow fall the array should be higher from the ground to prevent snow
building up at the lower edge of the array as it slides off, thus causing the array to be
shaded.
iii. Some key things to consider regarding location are vegetation, snow, material that may
drift around the array, future development, and other possibilities for future shading
problems.
iv. Decisions around this issue can be a balance between location conditions, O&M costs
for periodic removal of shading problems, and specifications for the ground under the
array (e.g., weed barriers and gravel).

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  Perimeter fence:
i. Confirm the fence doesn’t shade the array.
ii. It is a good idea to restrict access and keep out tumbleweeds and animals that may
damage the system.

Electrical Design:
Based on one-line or three-line diagram:
 Final electrical design has engineer’s stamp
 __________ (volts) Check PV string maximum/minimum voltages (extreme weather) and
confirm within inverter specifications (most inverters have a “string calculator” on their site,
for example:www.aesolaron.com/SolarStringCalc.aspx)
 __________ (kW) Check PV array maximum DC power to each inverter (extreme
weather-cold and clear) to confirm it is within inverter specifications.
 PV-each string protected (fuse or breaker)
 __________ (% efficiency, configuration & capacity) Transformer specification
(recommended minimum efficiency of 97%)
 Module grounding: confirm there is a specific grounding wire or the rack/module system is
Underwriters Laboratories rated for grounding
 AC disconnects specified and location easily accessible
 DC disconnects specified and location easily accessible.

Interconnection: Inside building must meet NEC 690:

Sum of PV breaker and panel main breaker less than or equal to 120% of panel rating
 __________ (amps) Panel rating
 __________ (amps) Panel main breaker rating
 __________ (amps) PV Breaker

Interconnection: Direct tie:

 Is there an acceptable plan?

System Components Specifications:

 System components meet “Buy American” criteria?

 PV CEC approved?

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  Inverter(s) CEC approved?
 __________ % Inverter efficiency
 __________ (years) Inverter warranty (recommended 10 year minimum)
 __________ PV module warranty (recommended 10 year 90%, 20 year 80% minimum)

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 Appendix E. PV Commissioning Checklist

(See IEC 62446 for more details)

Before Commissioning
The items below should be completed before commissioning or available at the site.
 All permits have been signed off
 Utility has given permission to operate system
 One or three line drawing of system
 System layout drawing (shows module layout, location of BOS components, disconnects,
and wiring and conduit specifications)
 PV module specifications
 Inverter specifications
 Combiner box specifications
 Feasibility Study Review (if available)
Visual Inspection
Verify the installation is complete to the design drawing.
 All PV modules are permanently installed (confirm modules are in good condition)
 All inverters permanently installed
 All combiner boxes permanently installed
 All disconnects and switchgear permanently installed

 Wiring is completed (no loose connections or damaged wires)

 No potential for wire damage (e.g., deburred metal and proper sheathing to protect wires)
 Utility power connected
 Internet connection operational (if applicable)
 Physical installation is per design drawing and manufacturer’s specification, and it meets
visual requirements
 System is compliant with applicable building and electrical codes
 Protective fencing and enclosures are installed

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  Verify outdoor equipment is of proper material for location (e.g., UV-rated wire, stainless
steel, hot dipped galvanized, other as specified)
 Dissimilar metal should be electrically isolated to avoid galvanic corrosion
 Verify grounding of metallic surfaces that might become energized
 Wire and conduit sizes installed per plan
 Fuses and breakers are sized and installed properly
 Document as-built conditions
 All equipment is labeled as required.
Performance Testing
Verify the system is performing within acceptable limits.
 Conductor insulation test using a megohm meter on all homerun wiring to ensure no
leakage currents to earth (Pos-to-GND and Neg-to-Gnd resistance > 2 megaohms). This may
need to be done during construction while conductors are accessible.
 Grounding resistance is < 5 Ohms
 Measure and record open-circuit voltage (Voc) and polarity of each string. (Verifies all
strings have the same number of modules.)
 Measure and record short-circuit current (Isc) of each string.
 Inverter startup sequence – follow manufacturer’s instructions for initial startup.

 Measure and record maximum power point current (Imp) for each string. (Current
measurements for each string should be within a 0.1A range of each other, assuming
consistent weather conditions and all string having same tilt and azimuth angle. If a string is
outside the range, check for shading or a ground fault.)
 Confirm inverter’s internal power meter and display using independent meters. (Once this
is done, inverter-displayed power readings can be used for subsequent reporting.)
 Confirm the system output under actual conditions meet minimum expected output.
Actual performance should be within about 5% of expected, calculated performance. This
procedure includes system nameplate rating (kW), solar irradiance measurement (W/m2) and
module cell temperature (C). Procedure is best conducted during consistent weather
conditions, where no array shading is present, and solar irradiance is not less than 400 W/m2.

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 Appendix F. Example of Requirements for a PV System
TABLE OF CONTENTS

DIVISION 01 - GENERAL REQUIREMENTS

01 11 00 Summary of Work
01 14 10 Use of Site
01 33 00 Submittals
01 33 26 Electrical Drawings and Data
01 35 10 Safety Data Sheets
01 35 20 Safety and Health
01 42 10 Reference Standards
01 46 00 Quality Procedures
01 55 00 Vehicular Access and Parking
01 56 10 Protection of Existing Installations
01 60 00 Product Requirements
01 74 00 Cleaning and Waste Management
01 78 30 Project Record Documents

DIVISION 03 - CONCRETE

03 20 00 Concrete Reinforcing
03 30 00 Cast-In-Place Concrete

DIVISION 05 - METALS

05 50 00 Metal Fabrications

DIVISION 26 - ELECTRICAL

26 05 02 Basic Electrical Materials and Methods

26 31 10 Photovoltaic System

DIVISION 31 - EARTHWORK

31 23 00 Earthwork Excavation, Fill, and Compaction

31 23 39 Disposal of Excavated Materials

DIVISION 32 - EXTERIOR IMPROVEMENTS

32 39 10 Bollards

DIVISION 52 - DRAWINGS

52 00 05 Sketches

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 SECTION 26 31 10
PHOTOVOLTAIC SYSTEM

PART 1 GENERAL

1.01 BACKGROUND

A. Reclamation FACILITY issuing a “Request for Proposal: for designing, furnishing,

installation, and/or delivery of the following photovoltaic systems:

1. First photovoltaic system shall be a (ground mount, roof mount) sized at xx kWAC
(approximate xx kWDC) grid-tied for main facility usage.

1.02 DESCRIPTION

A. Contractor’s proposal shall be for a firm-fixed price contract to design-build, install,

and/or deliver the following photovoltaic systems:
1. One ground mount grid-tied photovoltaic system providing approximate xx kWAC
(approximate xx kWh/year for an average year using typical weather data.

B. Contractor shall provide all labor, equipment, transportation, material, supplies, permits,
and certifications to design, furnish, install, test, deliver, and commission all four
photovoltaic systems.
1. The xx kWAC grid-tie system includes trenching, backfilling, compaction,
underground conduits, cabling, access boxes, labor, equipment, inverters, panels,
etc. to connect photovoltaic system to BOR FACILITY existing main electrical
service 208/480 V switchgear located approximately xx linear feet from
photovoltaic panel installation site.

1.03 MEASUREMENT AND PAYMENT

A. Offeror’s proposal shall provide payment schedule and recommended contract line items.

1.04 REFERENCE STANDARDS

A. International Code Council (ICC)

1. IBC-latest International Building Code

B. International Electrotechnical Commission (IEC)

1. IEC 61215:latest Crystalline Silicon Terrestrial Photovoltaic (PV)
Modules - Design Qualification and Type Approval
2. IEC 61853-1:latest Photovoltaic (PV) Module Performance Testing and
Energy Rating

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 3. IEC 62446:latest Grid Connected Photovoltaic Systems - Minimum
Requirements for System Documentation,
Commissioning Tests and Inspection
4. IEC 62759-1:latest Photovoltaic (PV) Modules - Transportation Testing
- Part 1: Transportation and Shipping of Module
Package Units

C. National Fire Protection Association (NFPA)

1. NFPA 70-latest National Electric Code

D. Underwriters Laboratories (UL)

1. UL 1703-02 Flat-Plate Photovoltaic Modules and Panels
2. UL 2703 Mounting Systems, Mounting Devices,
Clamping/Retention Devices, and Ground Lugs for
use with Flat-Plate Photovoltaic Modules and
Panels

1.05 SUBMITTALS

A. Submit the following in accordance with Section 01 33 00 - Submittals.

B. RSN 26 31 10-1, Manufacturer’s Product Data:

1. Approval data for each PV system component includes modules, inverters, panels,
mounts, etc.

C. RSN 26 31 10-3, PV Performance Report (PVPR):

1. Contractor shall prepare a written report of inspections and tests perform during
installation of PV modules and array systems. The report shall include the
following data and information:
a. Comparison of manufacturer’s data to field observations and tests.
b. Report includes array location, date of tests, list of tests being performed,
name of personnel performing tests or recording information, and list of
equipment.
1) If required, name of personnel performing peer review/quality
control or witnesses to tests.
2) Equipment list includes manufacturer’s data sheet, purpose of
equipment, methods and techniques use with equipment during
measurements, and last date equipment was calibrated.

D. RSN 26 31 10-4, xx kWAC Single Line Diagram:

1. Furnish a printed and electronic (Adobe “pdf” or AutoCAD “dwg” file formats)
single line diagram of xx kWAC Grid-Tie ground based photovoltaic system.

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 E. RSN 26 31 10-6, Interruption of Service Request:

1. List utility and location where interruption will occur.

2. Outline procedures for accomplishing work including specific safety precautions

to be taken, methods for Tag-Out & Lock-Out, usage of barricades and warning
signage, etc.

3. Commencement and duration of work.

4. Indicate that required materials are on site and ready for installation.

F. RSN 26 31 10-7, Operation Manual(s):

1. Submit for each system component following detailed instructions:
a. Detail step by step procedures for Startup, Normal Operations, and Shut
Down.
b. Detail step by step procedures for Emergency Operations include Shut
Down.
c. Detail step by step procedures for programming components which
includes a list of default program values, variables, set points, wiring
diagrams, and key instructions.
d. Detail step by step procedures for PV System maintenance activities.
1) Maintenance activity list shall include recommended interval
period(s) including a description of activity for PV System
components requiring maintenance.
a) Pertinent information shall include preventative
maintenance intervals and replacement list of components.
b) Provide recommended manufacturer products for such
items as cleaning agents, fuses. etc.
c) Revise operation’s manuals due to field adjustment or
correction during installation.
e. Detail step by step procedures for PV System components which require
removal and installation as part of maintenance or replacement due to
failure.
f. Submit according to “Section 01 78 30 – Project Record Documents” an
Equipment and Warranty List.
2. Submit information in electronic format such as Adobe “pdf”, Microsoft Word
“doc”, or AutoCAD “dwg” file formats.

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 G. RSN 26 31 10-8, As-Built drawings:
1. Provide “As-Built” drawings xx kWAC grid-tie ground mount PV system include
foundations, supports, brackets, trenching, electrical wiring diagrams, field
adjustments, etc.
2. Submit “As-Built” drawings in electronic format such as Adobe “pdf” or
AutoCAD “dwg” file formats.

1.06 OFFEROR’S PROPOSAL

A. Offeror shall estimate performance of the PV modules energy delivery and the complete
PV system. The power ratings are for Standard Test Conditions (STC) of 1000 W/m2
solar irradiance at 25ºC PV module temperature.

The STC power value, inverters, and system losses will be entered into a System Advisor
Model (SAM) or similar program to determine estimated energy delivery in kWh. The
estimated energy delivery shall be based on average weather for LOCATION for the
following PV systems:

1. AC energy delivery:

a. xx kWAC PV grid-tie ground mount PV system.

2. The Government’s preferred model is from NREL, other similar models will be
acceptable to the Government.

a. The STC power values, inverters, switches, and associate losses will be
entered into SAM to determine average estimated energy delivery in kWh
per month and year. Offeror shall document equipment and material
performance factors including design assumptions used in the SAM.

B. Offeror shall provide a One-Line diagram showing all major components such as PV
panels and array orientation, disconnects, inverters, transformers, utility lines, meters, etc.
for each of the propose PV systems.

C. Offeror shall provide sufficient details on foundation and mounting systems for the
xx kWAC grid-tie PV system.

1. Manufacture model data and shop drawings.

2. Tracking is not allowed for this project.

D. Offeror shall provide construction schedule starting from time of contract award to
completion of PV systems and commissioning, in calendar days. The following are
potential key elements for consideration in construction schedule:

1. At 90% complete design of the PV systems include a 14-day Government review

and comment period.

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 2. Lead time for permits, materials, deliveries, key coordination meetings, and
working with utilities for commissioning of PV system.

3. Mobilization and preparations of project site(s).

4. Begin and finish dates for construction of foundations, supports, and bollards for
each of the four PV systems.

5. Begin and finish dates for installation of panels and electrical systems.

6. Testing and commissioning of all four PV systems.

7. Demobilization from project site.

8. Please note any additional key milestones.

E. Offeror should describe method of controlling vegetation growth under panel arrays.

F. Offeror should describe method of constructing bollards and installation process.

G. Price Proposal:
1. Offeror’s shall break down price proposal per each of the four PV systems and list
all major cost components such as materials, equipment, and labor.
2. Offeror’s price proposal shall be valid for 90 days, from Government’s receipt.
H. Evaluation Criteria:
1. Offeror’s proposal will be evaluated on best value to the Government and the
following criteria:
a. Government considers Tier 1 PV modules have higher overall value in
each PV systems.
b. Offeror’s ability to demonstrate ability to provide warranty coverage and
technical support of PV systems supplied under this RFQ.
c. Offeror’s past performance.
d. PV Systems components, approach, and mythology will be evaluated
during the selection process, but the focus will be placed on the AC energy
delivery and cost in $/kWh.

PART 2 PRODUCTS

2.01 PHOTOVOLTAIC SYSTEMS

A. PV systems shall be fully operational and allow automatic operation without operator
intervention. Each PV system shall have the following key elements:

1. Each PV system shall minimize maintenance requirements.

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 2. Offeror shall provide onsite and remote access to PV power production data.
Manufacturer or vendor shall provide web-based remote access to PV system
real-time system performance data. System performance data shall include at a
minimum solar irradiance, ambient air temperature, AC real time power
production, and ability to see hourly outputs and recall hourly, daily, monthly, and
yearly production data.

2.02 COMPONENTS

A. Photovoltaic Modules (Solar Electric):

1. Tier 1 PV Modules shall meet or exceed the following standards:

a. UL - Standard 1703 Standard for Safety for Flat-Plate Photovoltaic

Modules.

b. IEC 61215 Crystalline Silicon Terrestrial Photovoltaic (PV) Modules-

Design Qualification and Type Approval.

c. PV modules shall be provided with a nameplate with key electrical design

information such as rated power, short circuit current, open circuit voltage,
and datasheet including details such as coefficients relating how these
parameters change with temperature.

d. Offeror shall furnish and supply to Reclamation spare (replacement) PV

modules totaling 1% plus one module based on total number of installed
modules, if different panels are used for grid-tie and off-grid PV systems
supply spare PV modules of each type.

e. Foundation supports, and mounting hardware shall be corrosion resistant.

f. PV arrays shall be a minimum of 12 inches above the ground surface.

2. PV modules and components shall be rated and warranted to withstand and

operate under temperature extremes and humidity conditions found at BOR
FACILITY.

B. Inverters, disconnects, boxes, enclosures, panel boards, etc.:

1. Key components such as disconnects, inverters, and panel boards shall be located
in accessible area, weather-protected, and secure.
2. Electrical metal components shall be bonded to the ground conductors.

3. Inverters shall be UL 1741 approved, located away from direct sunlight, and have
a minimum 10-year warranty.

a. Approved list of inverters can be found at the following website:

http://www.gosolarcalifornia.ca.gov/equipment/inverters.php.

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 C. Transformers:
1. If required, NEMA Premium.

2.03 ELECTRICAL EQUIPMENT

A. Furnish all cables, conduits, terminations, and accessories required for interconnecting
the equipment included in this Section.

B. Power and control cables: Designed for outdoor use, with a water, oil, and ultraviolet-
light resistant cable jacket.

2.04 PROTECTIVE COATINGS

A. Epoxy, powder coats, acrylic, and anti-reflection coatings are lead and chromate free.

B. Manufacturer or suppliers when available use green alternates as described at US. EPA
Comprehensive Procurement Guidelines available online at
http://www.epa.gov/epawaste/conserve/tools/cpg/index.htm.

C. Volatile Organic Compounds (VOC):

1. Do not exceed maximum permitted by federal, state, and local air pollution
control regulations. Do not exceed maximum content as supplied in container or
by addition of thinner material.

2. Use thinners recommended by manufacturer for each coating material.

D. Color or Tint: Supply according to Government approved submittal. If damage requires

repairing at project site do not color or tint at jobsite.

1. Color and gloss to meet one or more of following:

a. Munsell Book of Color.

b. Fed Std 595B.

c. Manufacturer’s standard color.

2. Gloss abbreviations:

a. FG: Full Gloss.

b. SG: Semigloss.

c. F: Flat.

3. Color, tint, and gloss of final coats to be approved by the Government prior to
application.

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 PART 3 EXECUTION

3.01 PROTECTIVE COATINGS

A. Delivery, Storage, and Handling of Coating Materials or Products:

1. Deliver materials, products, or supplies to jobsite in original, undamaged,

unopened packaging or crates. Include any special instructions for unloading or
repair of damage coatings.

2. Comply with manufacturer’s storage instructions.

B. Damage to coating systems shall be repaired according to manufacturer, supplier, or

coating applicator recommendations.

1. Protect items or surfaces not to be coated when repairing damaged coatings.

2. Protect from abrasive blast particles and airborne coating particles.

3. Repair within minimum and maximum recoat window time in accordance with
coating manufacturer’s recommendations.

a. Repair pinholes, holidays, laps, voids, and other defects.

b. Inspect repaired areas for compliance with specifications.

C. Items to be coated:

1. Frame and support assemblies.

2. Brackets.

3. Electrical panels and components.

3.02 INSTALLATION

A. Install PV Systems (arrays) according to required kW output at locations shown in

Sketch ”A” entitled “Site Plan.”

B. Install PV System (arrays) components and accessories according to Offeror’s design

criteria per each array.

C. Verify existing underground utilities and infrastructure prior to trenching for connection
between 120 kW array and electrical service MS-1 (switchgear) as required by Offeror’s
design criteria.

3.03 INTERRUPTION OF SERVICE

A. Coordinate interruption of service with COR.

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 1. When Contractor’s work cannot be performed during approved IOS schedule,
notify COR that IOS is not required.

2. Modify IOS schedule and receive written (email is acceptable) Government

approval.

B. No specific interruption of service will be considered unless:

1. COR has reasonable assurance that materials and equipment are onsite for
performance of work.

a. Submittal have been reviewed or approved by Government.

b. Contractor will be prepared to perform work on date and during period of

time requested for specific interruption of service.

2. Interruption of service schedules will depend upon Government’s power demand

requirements and related operating conditions. Government reserves right to re-
schedule interruption of services for any period during 24-hour day, any day of
week.

3. Contractor shall inform the COR verbal within 2 hours prior to interruption of
service.

C. Interruption of services may be scheduled during off-peak periods, nights, or weekends.

D. Review submittals for accuracy and provide corrections if process or time schedule has
changed from time of submittal.

3.04 CONTRACTOR’S TESTING

A. Contractor shall perform inspections and tests according to IEC 62446 Grid connected
photovoltaic systems - Minimum requirements for system documentation, commissioning
tests and inspection” throughout the construction and commissioning processes.

B. Periodic “Quality” inspections shall be conducted to support progress payments as

identified in the contractor’s quality control plan.

1. Perform testing in presence of the Government representative.

2. Notify the COR a minimum of 5 days in advance of tests being performed.

C. Inspections and tests shall verify contract assumptions through documentation and
observations by Contractor’s Quality Control Personnel and certify work
accomplishments and attainment performance of PV systems.

1. Unless otherwise identified, manufacturer recommendations shall be followed

during all inspections and test procedures.

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 2. Commissioning Array Tests shall include the following:

a. Measure and record individual string voltages, current, and solar

irradiance as measured in the plane of the PV array.

b. Conduct and record IV curve trace of each strings compared to panel

manufacture data. This data shall be used to confirm proper performance
of the PV system.

c. After completion of inspections and tests the Offeror shall provide a

written report of comparisons and data observations. Provide electrical
copy of the PV Array Performance Report (PVPR) to the COR. The
PVPR shall include the following information for each PV module and
array systems:

1) Location of testing, date of tests, list of tests performed, and name

of personnel performing tests, recording data, and if required name
of peer review or witnesses to testing activities.

2) The PVPR shall include the following information such as date of

equipment calibration, describe equipment and purpose, and
methods/techniques used during measurements.

3) At time of tests record present state of PV array construction and

operating phase of PV array.

d. In addition, the PVPR shall include system performance (model based)

estimates compared to actual field installed performance. Include at a
minimum solar irradiance, DC and AC energy outputs, ambient air
temperature, and PV cell temperatures. PV System performance shall be
measured and reported for a performance period of 72 hours.

1) During performance monitoring of the installed PV System arrays

indicate that kW productions are lower than expected, the
Contractor shall investigate and repair to meeting required kW
production outputs at the Contractor’s expense.

2) After adjustments or repairs Contractor shall perform performance

monitoring until PV System arrays meets required kW output.

3) Measurements made under actual installation and temperature will

be normalized to STC.

3.05 ACCEPTANCE

A. Upon completion of each PV array and after commissioning array tests, the Offeror shall
demonstrate the performance of the system to the Government.

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 1. Acceptance shall be after one week of performance measurement at a cell
temperature corrected Performance Ratio (PR) of 90% or greater with 100%
system availability.
2. Document all performance measurements.

3.06 TRAINING

A. Provide 8-hour onsite training covering the following:

1. Instruct the Government in operation and maintenance of each PV array system

and components. Including written instructions and procedures for all key
components of each PV array. Key elements include:

a. Inverters, disconnects, panels, and other prudent equipment.

b. Supply manufacturer’s specified equipment required to perform

maintenance or repairs of PV systems.

c. Review with the Government Contractor’s recommended spare parts or

component lists. List shall be sufficient to allow for Government
procurement.

d. Government reserves the right to video tape training session for official
use only.

B. Contractor (Offeror) shall provide technical support for a two year period after
Government has made final payment.

3.07 WARRANTIES

A. Provide warranties in accordance with the clause at FAR 52.246-21 “Warranty of

Construction,” the specifications, and this section.

B. Warranty of Construction

1. Submit data concerning warranty of construction, required by the clause at FAR

52.246-21 “Warranty of Construction” including the warranty period (dates), and
warranty contacts with names, addresses, and telephone numbers.

a. Government requires the construction warranty for a period of five (5)

years from date of substantial completion. This warranty requires four
additional years of warranty over the base one year provided in clause
FAR 52.246-21 “Warranty of Construction” for all equipment, materials,
supplies, etc. to the installation of the PV systems.

C. Warranties for PV System Components

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 1. For PV component warranties, including those warranties for equipment supplied
under this RFQ include manufacturer or brand name and model.

2. Warranty List:

a. Provide electronic document containing a complete list of all warranted

equipment, products, materials, processes, and other warranted items
furnished under this contract. Fully execute and deliver this “Warranty and
Equipment List” to the Government within 14 days after receiving written
notice of substantial completion. One approved format for the “Warranty
and Equipment List is as follows:

WARRANTY AND EQUIPMENT LIST

Contract No.: Title:

Contractor’s Information (include name, addresses, phone number, and contact person):
Business Name:
Point of Contact:
Address:
Phone No.:
Email:

Manufacturer’s Model and Serial Warranty Period Location of

Warranty Item(s) Information Number(s) and Dates Component
PV Modules (Installed)
PV Modules (Spares)
PV Modules (Replacement)
Inverters
Disconnects and Panels
Meters
Solar Array Mounting Racks
Software
Other PV Components

D. Mobile PV generator shall have a minimum warranties:

1. PV modules (panels): 25 years, minimum.
2. PV components: 5 years, minimum.
3. PV battery packs: 7 years, minimum.

END OF SECTION

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 Appendix G. Service Descriptions for Preventive
Maintenance

ACTIVITY COMPONENT DESCRIPTION INTERVAL SERVICE

AREA PROVIDER
Cleaning PV Module Clean PV modules with plain water or Condition or Module Cleaning
General mild dishwashing detergent. Do not use study
brushes, any types of solvents, abrasives, dependent
or harsh detergents.

Cleaning PV Module Snow Removal Condition or Module Cleaning

study
dependent
Cleaning PV Module Dust: Agricultural /Industrial/Pollen Condition or Module Cleaning
Cleaning study
dependent
Emergency System Contractor available by email and phone Ongoing Journeyman
Response 24x7x365 Electrician
Inspection AC Wiring Inspect electrical boxes for corrosion or Annual Electrician
intrusion of water or insects. Seal boxes if
required.
Inspection AC Wiring Check position of disconnect switches and Annual Electrician
breakers.
Inspection AC Wiring Exercise operation of all protection Annual Electrician
devices.
Inspection AC Wiring AC disconnect box inspection Annual Electrician
Inspection DC Wiring Test system grounding with “megger” Annual Electrician
Inspection DC Wiring Scan combiner boxes with Infrared Annual
camera to identify loose or broken
connections
Inspection DC Wiring Inspect cabling for signs of cracks, Annual Electrician
defects, pulling out of connections;
overheating, arcing, short or open
circuits, and ground faults.
Inspection DC Wiring Check proper position of DC disconnect Annual Electrician
switches.
Inspection Combiner and Open each combiner box and check that Annual Electrician
Junction Boxes, no fuses have blown and that all electrical
DC Wiring connections are tight. Check for water
incursion and corrosion damage. Use an
infrared camera for identifying loose
connections because they are warmer
than good connections when passing
current.
Inspection DC Wiring Look for any signs of intrusion by pests Annual Vermin Removal
such as insects and rodents. Remove any
nests from electrical boxes (junction
boxes, pull boxes, combiner boxes) or
around the array. Use safe sanitation

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 ACTIVITY COMPONENT DESCRIPTION INTERVAL SERVICE
AREA PROVIDER
practices because pests may carry
disease.
Inspection Inverter Observe instantaneous operational Monthly Inspection
indicators on the faceplate of the inverter
to ensure that the amount of power being
generated is typical of the conditions.
Compare current readings with diagnostic
benchmark. Inspect Inverter housing or
shelter for physical maintenance required
if present.
Inspection Monitoring Spot-check monitoring instruments Annual PV Module/Array
(pyranometer, etc.) with hand-held Specialist
instruments to ensure that they are
operational and within specifications.
Inspection PV Array Test open circuit voltage of series strings Annual Journeyman
of modules. Electrician
Inspection PV Array Check all hardware for signs of corrosion, Annual Mechanical
and remove rust and re-paint if necessary. Technician

Inspection PV Array Walk through each row of the PV array Annual PV Module/Array
and check the PV modules for any Specialist
damage. Report any damage to rack and
damaged modules for warranty
replacement. Note location and serial
number of questionable modules.
Inspection PV Array Inspect ballasted, non-penetrating Annual Mechanic
mounting system for abnormal
movement.
Inspection PV Array Determine if any new objects, such as Annual Tree Trimming
vegetation growth, are causing shading of
the array and move them if possible.
Remove any debris from behind collectors
and from gutters.
Inspection PV Module Use infrared camera to inspect for hot Annual PV Module/Array
spots; bypass diode failure. Specialist
Inspection Transformer Inspect transformer meter, oil and Annual Journeyman
temperature gauges, include housing Electrician
container, or concrete housing if
presentment.
Inspection Controller Check electrical connection and enclosure Annual Electrician
for tracking motor/controller.
Inspection Motor Check electrical connections. Annual Electrician
Inspection DC Wiring Check grounding braids for wear. Annual Electrician
Inspection Transformer Transformer/switchgear inspection. Annual Electrician
Inspection Tracker Anenometer Inspection. Annual Inspector
Inspection Tracker Driveshaft torque check & visual Annual Mechanical
inspection. Technician
Inspection Tracker Inclinometer inspection Annual Mechanical
Technician

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 ACTIVITY COMPONENT DESCRIPTION INTERVAL SERVICE
AREA PROVIDER
Inspection Tracker Limit switch inspection Annual Mechanical
Technician
Inspection Tracker Module table inspection Annual Mechanical
Technician
Inspection Tracker Screw jack inspection Bi-annual Mechanical
Technician
Inspection Tracker Slew gear torque check & wear Bi-annual Mechanical
inspection. Technician
Inspection Tracker Torque inspection Annual Mechanical
Technician
Inspection Tracker Tracking controller inspection Annual Mechanical
Technician
Inspection Tracker Universal joint inspection, gears, gear Annual Mechanical
boxes, bearings as required or Technician
documented by manufacturer.
Inspection PV module PV module torque check & visual 5 years PV Module/Array
inspection. specialist

Inspection PV module Racking torque check and inspection 5 years PV Module/Array

specialist
Inspection PV module Inspection: corrosion and encapsulate Annual PV Module/Array
yellowing specialist

Inspection PV Module Galvanization inspection Annual PV Module/Array

Specialist
Management Asset Daily Operations and Performance Ongoing Admin Asst.
Management Monitoring
Management Asset Monitor alarms and site-specific alert As needed Journeyman
Management parameters. Electrician
Management Asset Manage inventory of spare parts As needed Journeyman
Management Electrician
Management Asset Monitoring annual service package Ongoing Admin Asst.
Management
Management Documents Document all O&M activities in a Ongoing Admin Asst.
workbook available to all service
personnel.
Management Documents Confirm availability and take any Monthly Admin Asst.
measures to secure operating
instructions, warranties and performance
guarantees, and other project
documentation.
Management Documents Review O&M agreements and ensure that As needed Admin Asst.
services are actually provided.
Management Documents Update record with preventative Ongoing Admin Asst.
maintenance activities and track any
problems or warranty issues and secure
the record onsite.
Management Documents Meet with key site staff to continue Annual Inspection
awareness, question any issues, and
report on findings.

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 ACTIVITY COMPONENT DESCRIPTION INTERVAL SERVICE
AREA PROVIDER
Management Meter Maintain a log of cumulative power Monthly Admin Asst.
delivery (kWh to date) and chart this
value against date. Chart the value even
for uneven or infrequent intervals. Explain
variation by season or weather.
Management Electrical Electrical labor mobilization Annual Master
Electrician
Management Mechanical Mechanical labor mobilization Annual Admin Asst.
Management IT Check central SCADA/network manager, Annual IT Specialist
include software IT and IT hardware
updates as required.
Service AC Wiring Re-torque all electrical connections on AC Annual Electrician
side of system.
Service DC Wiring Re-torque all electrical connections in Annual Journeyman
combiner box. Electrician
Service Instruments Exchange or re-calibrate instruments As per manuf. Journeyman
Electrician
Service Inverter Replace transient voltage surge As per manuf. Inverter
suppression devices Specialist
Service Inverter Install any recent software upgrades to 5 years Inverter
inverter programming or data acquisition Specialist
and monitoring systems.
Service Inverter Clean (vacuum) dust from heat rejection Annual Inverter
fins. Specialist
Service Inverter Replace any air filters on air-cooled As needed Inverter
equipment such as inverter. Specialist
Service PV Array Remove bird nests from array and rack Annual Vermin Removal
area.
Service PV Array Nesting vermin removal, nesting vermin Annual Vermin Removal
prevention.
Service Tracker Lubricate tracker mounting Annual Mechanical
bearings/gimbals as required by Technician
manufacturer.
Service Tracker Lubricate gearbox as required by Bi-annual Mechanical
manufacturer. Technician
Service Tracker Screw jack greasing as required by Bi-annual Mechanical
manufacturer. Technician
Service Tracker Slew gear lubrication as required by 3 years Mechanical
manufacturer. Technician
Service Tracker Universal joint greasing (zerk fitting) as Bi-annual Mechanical
required by manufacturer. Technician
Testing Documents Perform performance test: measure Annual PV Module/Array
incident sunlight and simultaneously Specialist
observe temperature and energy output.
Calculate PV module efficiency as a
function of temperature and calculate the
balance-of-system efficiency. Compare
readings with diagnostic benchmark
(original efficiency of system).

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 ACTIVITY COMPONENT DESCRIPTION INTERVAL SERVICE
AREA PROVIDER
Testing Inverter Test overvoltage surge suppressors in 5 years Inverter
inverter. Specialist
Testing PV Module Test output of modules that exhibit Annual PV Module/Array
cracked glass, bubble formation oxidation Specialist
of busbars, discoloration of busbars, or PV
module hot spots (bypass diode failure).
Testing PV Module Test modules showing corrosion of Annual PV Module/Array
ribbons to junction box Specialist

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 Appendix H. Service Descriptions for Corrective Maintenance
The following is a list of corrective/reactive maintenance measures that would be performed to fix
problems encountered in operation of a PV system over time.

ACTIVITY COMPONENT SERVICE DESCRIPTION FREQUENCY/RESPONSE SERVICE

AREA TIME PROVIDER

Emergency System Dispatch contractor in response As needed Journeyman

Response to alarms, alerts, or contact by Electrician
others.
Repair AC Wiring Replace inverter AC fuse(s) As needed Electrician
Repair AC Wiring Replace protective devices As needed Electrician
(breakers) in building panel
Repair AC Wiring Replace broken/crushed AC As needed Electrician
wiring conduit and fittings
Repair AC Wiring Repair line-to-line fault As needed Electrician
Repair AC Wiring Locate line-to-line fault As needed Inspection
Repair DC Wiring Replace failed fuses in combiner As needed Electrician
box
Repair DC Wiring Replace MC Connectors As needed Electrician
between modules.
Repair DC Wiring Replace MC connector lead to As needed Electrician
combiner box.
Repair DC Wiring Re-route conduit As needed Electrician
Repair DC Wiring Replace broken/crushed Dc As needed Electrician
wiring conduit and fittings.
Repair DC Wiring Repair ground fault As needed Electrician
Repair DC Wiring Locate ground fault As needed Electrician
Repair DC Wiring Locate underground DC wiring As needed Specialist
as part of repairs to faults.
Repair DC Wiring Replace fuse(s) on DC source As needed Master
circuits to inverter. electrician
Repair DC Wiring Seal leaking junction box As needed Journeyman
Electrician
Repair Inverter Replace fuse As needed Journeyman
Electrician
Repair Inverter Start/stop inverter (reboot to As needed Journeyman
clear unknown error). Electrician
Repair Inverter Replace inverter fan motor As needed Inverter
Specialist
Repair Inverter Replace inverter data acquisition As needed Inverter
card/board; diagnose with fault Specialist
code
Repair Inverter Replace inverter control card As needed Inverter
(PWM signal, voltage, phase, Specialist
frequency, shut-down); diagnose
with fault code
Repair Inverter Replace IGBT driver card/board; As needed Inverter
diagnose with fault code Specialist

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 ACTIVITY COMPONENT SERVICE DESCRIPTION FREQUENCY/RESPONSE SERVICE
AREA TIME PROVIDER

Repair Inverter Replace maximum power point As needed Inverter

tracker card/board; diagnose Specialist
with fault code
Repair Inverter Replace AC contactor in inverter As needed Inverter
Specialist
Repair Inverter Replace IGBT matrix in inverter As needed Inverter
Specialist
Repair Inverter Replace 24VDC power supply for As needed Inverter
inverter controls Specialist
Repair Inverter Replace DC contactor in inverter As needed Inverter
Specialist
Repair Inverter Replace surge protection in As needed Inverter
inverter Specialist
Repair Inverter Replace GFI components in As needed Inverter
inverter Specialist
Repair Inverter Replace capacitors in inverter As needed Inverter
Specialist
Repair Inverter Replace inductors (coils) in As needed Inverter
inverter Specialist
Repair Inverter Replace fuses internal to As needed Inverter
inverter Specialist
Repair Inverter Replace inverter relay/switch As needed Inverter
Specialist
Repair Inverter Replace overvoltage surge As needed Inverter
suppressors for inverter Specialist
Repair Inverter RE-install inverter control As needed Inverter
software Specialist
Repair Inverter Manual reset of arc-fault trip As needed Inverter
(NEC 690.11) Specialist
Repair Monitoring Restore lost internet connection As needed Network/IT
Repair PV Array Excavate and replace failed As needed Structural
foundation element. Engineer
Repair PV Array Repair or replace rack parts As needed PV
damaged by corrosion or Module/Array
physical damage. Specialist
Repair PV module Replace modules failing As needed Electrician
performance test after showing
cracks in glazing, discoloration of
metallic contacts, delamination
or signs of water in.
Repair PV module Repair cracking of PV module As needed PV
back sheet. Module/Array
Specialist
Repair PV module Repair or replace damage to As needed Specialist
module frame.
Repair Roof Repair roof leaks as related to As needed Roofer
PV structure penetrations
problems.

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 ACTIVITY COMPONENT SERVICE DESCRIPTION FREQUENCY/RESPONSE SERVICE
AREA TIME PROVIDER

Repair Roof Re-roof (new roof) as related to As needed Roofer

PV structure penetrations
problems.
Repair Roof Roof tile repair leaks as related As needed Roofer
to PV structure penetrations
problems.
Repair Tracker Repair/replace tracker drive As needed Mechanical
shaft Technician
Repair Tracker Replace tracker drive bearing As needed Mechanical
Technician
Repair Tracker Replace tracker mount bearing As needed Mechanical
Technician
Repair Tracker Replace tracker motor controller As needed PV
Module/Array
Specialist
Repair Tracker Replace/upgrade tracker control As needed PV
software Module/Array
Specialist
Repair Tracker Replace tracking controller As needed Mechanical
power supply fan filter Technician
Repair Tracker Replace hydraulic cylinder As needed Mechanical
Technician
Repair Transformer Replace transformer As needed Electrician
Repair Transformer Re-tap transformer As needed Electrician
Repair Inverter Replace terminal block As needed Journeyman
Electrician
Repair IT, internet Repair/Replace repair onsite As needed IT
connections IT, internet connections
Repair Monitoring Replace monitoring components As needed Journeyman
Devices at combiner boxes Electrician
Repair Environmental Repair/replacing environmental As needed Journeyman
Sensors sensors Electrician
Repair Combiner Boxes Repairing/replacing combiner As needed Journeyman
boxes (DC, AC side) Electrician
Repair Inverter Replace inverter As needed Journeyman
Electrician
Repair AC Wiring Locate underground AC wiring As needed Utilities
Locator

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 Appendix I. The Basics of Lifecycle Cost Analyses
Supporting Reclamation’s Sustainable Energy Goals

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Economics Technical Memorandum No. EC-2013-02

The Basics of Lifecycle Cost Analyses

Supporting Reclamation’s Sustainable
Energy Goals

U.S. Department of the Interior

Bureau of Reclamation
Technical Service Center
Denver, Colorado August 2013
81
MISSION STATEMENTS

The U.S. Department of the Interior protects America’s natural

resources and heritage, honors our cultures and tribal communities,
and supplies the energy to power our future.

The mission of the Bureau of Reclamation is to manage, develop,

and protect water and related resources in an environmentally and
economically sound manner in the interest of the American public.

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Economics Technical Memorandum No. EC-2013-02

The Basics of Lifecycle Cost Analyses

Supporting Reclamation’s Sustainable
Energy Goals

U.S. Department of the Interior

Bureau of Reclamation
Technical Service Center
Denver, Colorado August 2013
83
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ACRONYMS AND ABBREVIATIONS

BLCC5 Building Lifecycle Cost Program

DOE Department of Energy

FEMP Federal Energy Management Program

Guiding Principles Guiding Principles for Federal Leadership in High

Performance and Sustainable Buildings

kg kilograms

LCA life cycle cost analysis

MOU Federal Leadership in High Performance and Sustainable

Buildings Memorandum of Understanding

NECPA National Energy Conservation Policy Act

NIST National Institute of Standards Technology

NREL National Renewable Energy Lab

OMB Office of Management and Budget

P&Gs Economics and Environmental Principles and Guidelines

for Water and Related Land Resources Implementations
Studies

PG&E Pacific Gas and Electric Company

PV present value

Reclamation Bureau of Reclamation

SAM System Advisor Model

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CONTENTS
Page

1.0 Introduction ................................................................................................. 1

2.0 Basic Economic Concepts........................................................................... 2
2.1 Time Value of Money ......................................................................2
2.2 Compounding...................................................................................2
2.3 Discounting ......................................................................................3
2.4 Discount Rates .................................................................................4
3.0 Federal Requirements for Economic Analyses ........................................... 6
3.1 Guidelines for LCAs Related to Energy and Water
Conservation and Renewable Energy ...........................................6
4.0 Analytical Methods for Project Evaluation................................................. 7
4.1 Benefit Cost Analysis ......................................................................7
4.1.1 Lifecycle Cost Analysis ...................................................... 8
4.2 Cost Effectiveness ............................................................................9
4.3 Savings to Investment Ratio ..........................................................10
4.4 Internal Rate of Return...................................................................11
4.5 Modified Internal Rate of Return ...................................................11
4.6 Payback Period...............................................................................12
5.0 Types of Capital Investment Decisions and Preferred Analysis
Method ................................................................................................... 14
6.0 Lifecycle Analysis Steps ........................................................................... 15
6.1 Project Description.........................................................................15
6.2 Collect Lifecycle Cost Data ...........................................................16
6.2.1 Data Requirements ............................................................ 16
6.3 Determine Discount Rate and Study Period ..................................18
6.4 Preparing the Lifecycle Cost Comparison and Results..................19
6.5 Documenting the Analysis .............................................................19
7.0 Tools for Conducting LCA ....................................................................... 19
7.1 Spreadsheet ....................................................................................19
7.2 SAM ...............................................................................................20
7.3 BLCC5 ...........................................................................................21
8.0 Other Non-Economic Decision Making Considerations .......................... 21
9.0 Recommendations ..................................................................................... 22

Glossary ................................................................................................................ 23

References ............................................................................................................. 25

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Tables
Table Page

1 Net benefits (Bt – Ct) for Investment A and Investment B ................... 3

2 Net present value estimates for a future one-time payment of
$500 using varying discount rates and years ..................................... 5
3 Summary of data requirements and potential sources ........................ 17
4 Recommended documentation items for a lifecycle cost analysis
report ................................................................................................ 20

Appendices
Appendix

A NREL Report Review

B LCA Example Using Building Lifecycle Cost Software

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1.0 INTRODUCTION

The Bureau of Reclamation’s (Reclamation) Research and Development Office

partnered with the National Renewable Energy Laboratory (NREL) in 2010 to
provide Geographic information System (GIS) screening and case studies analysis
for non-hydroelectric renewable energy at Reclamation facilities. This research
effort provided detailed examples of assessments for wind and solar renewable
energy generation installations at Reclamation land and facilities in order to
inform Reclamation policies and practices regarding developing non-
hydroelectric renewable energy (N-HRE). The details of these analyses can
be found in Hasse et al, 2013.
The purpose of this report is to provide further details related to the economic
analysis conducted by NREL. Further research identified legislation and
executive orders related to economic assessments of federal investments
associated with energy and water conservation and renewable energy in federal
buildings. A life cycle cost analysis (LCA) is the primary tool mandated by
legislation and executive orders for economic analysis of federal investments in
energy and water conservation and renewable energy in federal buildings. An
understanding of life cycle cost analyses will assist Reclamation staff in achieving
the goals for non-hydroelectric renewable energy at Reclamation facilities.

The specific goals of this effort are listed below.

1. Introduce basic economic concepts including time value of money,

compounding, discounting, and discount rates

2. Introduce analytical measures for project evaluation

3. Introduce the Federal requirements related to economic analyses

4. Outline the steps necessary for conducting an LCA

5. Discuss available tools for conducting an LCA

6. Discuss other non-economic decision making considerations

7. Provide general recommendations regarding LCA

8. Review of the National Renewable Energy Lab analysis (Haase

et al. 2013) on Lake Berryessa and Willows solar projects. This economic
evaluation was conducted for the Bureau of Reclamation (found in
Appendix A)

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9. Provide an example of an LCA (found in Appendix B).

2.0 BASIC ECONOMIC CONCEPTS

The purpose of this section is to provide the reader an understanding of several
basic economic concepts and techniques, including time value of money,
compounding, discounting, and discount rates.

2.1 Time Value of Money

The timing of benefits and costs are central to economic analyses of investment
related decisions. In all but the most unusual circumstances, a dollar received
today is worth more than a dollar received in the future. This concept, referred
to as the time value of money, is an important consideration when evaluating
investment decisions. For example investors will prefer receiving project benefits
as soon as possible and would rather pay project costs at a future date. There are
two techniques used in economic analyses to adjust for time value of money:
compounding and discounting.

2.2 Compounding
Compounding is the technique used to estimate the future value of money
invested or loaned today. For example, if $100 is invested today into a savings
account earning 5 percent interest during the year, it would be worth $105 at the
end of this year. This growth is called compounding. The higher the interest rate
the faster the investment compounds which increases the return on investment.

The compound amount or future value is calculated using equation (1).

(1)
𝐹𝑉 = 𝑃𝑉 ∗ (1 + 𝑖)𝑇

Where:

FV = Future value
PV = Present value or the amount invest in the present time
i = The annual interest rate or rate of return
T = The total number of years the investment is allowed to compound

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2.3 Discounting
Discounting is the opposite of compounding. Discounting is the technique for
estimating the present value, or today's value, of a benefit or cost to be received or
paid at later dates. For example if an individual is offered a single payment of
$500 in two years, assuming a discount rate of 5 percent, the present value can be
estimated using equation (2). Equation (2) is derived algebraically by solving for
Present Value in equation (1). Using equation 2, substituting $500 for the future
value (FV), 2 for (T), and 0.05 for (d) the present value (PV) is estimated as
$453.51.

(2)
𝐹𝑉
𝑃𝑉 =
(1 + 𝑑)𝑇

The more general form of equation (2) which accounts for both costs (C) and
benefits (B) over some period of time is shown in equation (3). This formula is
known as the Net Present Value (NPV) formula, the discounting formula, and/or
the future value formula. In equation (3), ∑ is the mathematical summation
operator, Bt is the benefit occurring at time (t), Ct is the cost occurring in time (t),
and (d) is the discount rate. In mathematical notation, time subscript (t) runs from
t=0, the time of the initial investment, to the final or terminal period, t=T.

(3)
𝑇
(𝐵𝑡 − 𝐶𝑡 )
𝑁𝑃𝑉 = �
(1 + 𝑑)𝑡
𝑡=0

Equation (3) is used in economics, engineering, and finance to compare the NPV
of investments made today which have costs and benefits in the future. An
example of this is shown in table 1. In this table the net benefits (Bt – Ct) for two
investment alternatives (Investment A and Investment B) are shown.

Table 1.—Net benefits (Bt – Ct) for Investment A and Investment B

Time 0 1 2 3 4 5

Investment A $-2,000 $0 $0 $0 $1,000 $3,000

Investment B $-2,000 $1,000 $500 $1,000 $500 $1,000

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As shown in table 1, each investment has the same initial investment cost of
($2,000). If one were to add up the net benefits of each investment option,
each would pay out $2,000. However this does not correctly account for the
timing of the costs and benefits and would result in the wrong investment
decision.

To correctly evaluate Investments A and B, one must account for the timing of the
costs and benefits. This requires calculating the NPV for each investment using
Equation (3). The NPV for Investment B, equals $1,464.61, using equation (3)
at a 5 percent discount rate. The details of this calculation are shown in
equation (4).

(4)

−2,000 1,000 500 1,000 500 1,000

𝑁𝑃𝑉𝐵 = (1+ .05)0
+ (1+ .05)1
+ (1+ .05)2
+ (1+ .05)3
+ (1+ .05)4
+ (1+ .05)5

Using equation (3) the NPV for Investment A equals $1,173.28. In this example
Investment B, results in a higher NPV. Therefore after properly accounting for
the timing of the costs and benefits, Investment B is a wiser investment compared
to Investment A. This example clearly shows how the timing of the net benefits
influences investment decisions.

2.4 Discount Rates

Discounting, as described above, is the method for converting costs and benefits
that occur at different points in time to a present value. The rate at which future
costs and benefits are discounted is called the discount rate 1 (parameter d in
Equations 3). The purpose of this section is to 1) demonstrate how discount rates
influence investment decisions, 2) describe the types of discount rates and 3)
provide general guidance on selecting the proper rate.

Economic analyses are very sensitive to discount rates. For example, using
equation (2), one can calculate the NPV using varying discount rates and years
in the future for a future one-time payment ($500 in this example). Table 2
illustrates that a higher discount rate reduces the present value of future benefits
and costs relative to a lower discount rate.

1
It should be pointed out that it is common to use the word “interest rate” however economists
typically use the term “discount rate”.

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Table 2.—Net present value estimates for a future one-time

payment of $500 using varying discount rates and years
Years in the future (T)
Discount rate 10 50 100
1.00% $452.64 $304.02 $184.86
3.00% $372.05 $114.05 $26.02
8.00% $231.60 $10.66 $0.23
10.00% $192.77 $4.26 $0.04

Discount rates are generally categorized as nominal or real discount rates.

The relationship between the nominal rate and the real rate is shown in
Equation (5).

(5)

𝑑 = (1 + 𝑟) ∗ (1 + 𝑖) − 1

Where:

d = Nominal discount rate

r = Real discount rate
I = Inflation rate

The real rate (parameter r) is the money paid for the use of capital, expressed
as a percentage per period that does not include a market adjustment for the
economy’s anticipated general price inflation rate. The inflation rate (parameter i)
is the percentage rate of change of the aggregate price level from one period to
another.

When using nominal discount rates in present value calculations benefits and
costs should be expressed in current dollars. Current dollars are dollars of non-
uniform purchasing power, including general price inflation or deflation, in which
actual prices are stated. Whereas when real discount rates are used in present
value calculations benefits and costs should be expressed in constant dollars.
Constant dollars are uniform purchasing power tied to a reference year (typically
the base year of the study) and are exclusive of general price inflation or
deflation. For analysis of federal investments the discount rate is often prescribed
in the federal requirements pertaining to the analysis. Many of these federal
requirements are discussed in Section 3.0 of this paper.

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3.0 FEDERAL REQUIREMENTS FOR ECONOMIC

ANALYSES
Office of Management and Budget (OMB) Circular A-94 provides general
guidance for analyses of federal investments. However, water resource projects
and Federal energy management programs are exempted from OMB A-94
(OMB Circular A-94, 4.b.1 and 4.b.3). The majority of Reclamation’s economic
analyses are subject to the Economics and Environmental Principles and
Guidelines for Water and Related Land Resources Implementations Studies
(P&Gs 2) (U.S. WRC, 1983).

Economic analyses for energy conservation and renewable energy investment

in new or existing federal owned or leased property must be performed in
accordance with Code of Federal Regulations, Title 10, Part 436, Subpart A,
Federal Energy Management and Planning Programs: Life Cycle Cost
Methodology and Procedures (10 CFR 436A). This CFR can be found on the
US Government Printing Web site at: http://www.ecfr.gov.

OMB Circular A-94 provides guidance on both economic benefit cost analyses
and economic cost effectiveness analyses. The P&Gs provide guidance for
performing economic cost benefit analyses.

3.1 Guidelines for LCAs Related to Energy and Water

Conservation and Renewable Energy
The National Energy Conservation Policy Act (NECPA) was signed into law in
1978. The NECPA serves as the underlying authority for federal energy
management goals and requirements. NECPA tasked the Department of
Commerce, National Institute of Standards Technology (NIST) with providing
technical assistance to the Department of Energy (DOE) and the Federal Energy
Management Program (FEMP) in developing and implementing lifecycle cost
methods related to energy and water conservation and renewable energy
investments. NIST provides guidance on the LCA method through several
publications which are discussed below.

2
The Water and Resource Development Act of 2007 instructed the Secretary of the Army to
develop updated P&Gs. In 2009 the Obama administration began the process of updating the
P&Gs and included Federal agencies engaged in water resource planning. In March 2013,
the administration released updated P&Gs called the Principles and Requirements. The
administration released the final set of Principles and Requirements that lay out broad principles to
guide water investments, and also released draft Interagency Guidelines for implementing the
Principles and Requirements. Once the draft Interagency Guidelines are finalized, each agency
will update its procedures that are necessary for their specific agency mission. The Principles and
Requirements take effect 180 days after the publication of the final Interagency Guidelines.

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The National Institute of Standards Technology (NIST) Handbook 135 – Life-

cycle Costing Manual for Federal Energy Management Program (FEMP) (Fuller
and Peterson, 1995) expands on the 10 CFR 436 methods and criteria. Handbook
135 provides an in depth tutorial on the LCA method. The Handbook describes
the LCA methods and assumptions and also provides several examples.
Handbook 135 can be found on NIST, Building and Fire Laboratory’s Web site
at: http://www.fire.nist.gov/bfrlpubs/build96/art121.html

A supplement to Handbook 135 is published annually (Rushing et al., 2012). The

supplement is entitled Energy Price Indices and Discount Factors for Life-Cycle
Cost Analysis, Annual Supplement to NIST Handbook 135 and NBS Special
Publication 709. The supplement provides the latest price indices and discount
rates for performing LCAs for Federal energy and water conservation and
renewable energy investments. The supplement can be found on the
following Web site: http://www1.eere.energy.gov/femp/information/
download_blcc.html#handbook

In 2012 Reclamation published “Interpretation of the Guiding Principles for

Federal Leadership in High Performance and Sustainable Buildings – Existing
Buildings.” This publication provides guidance and Reclamation’s interpretation
of the Guiding Principles for Federal Leadership in High Performance and
Sustainable Buildings (Guiding Principles). The Guiding Principles are defined
as a set of sustainable building requirements. This document also describes
Reclamation’s specific sustainable building requirements.

4.0 ANALYTICAL METHODS FOR PROJECT

EVALUATION
This section provides brief descriptions of the analytical methods that are
commonly used to evaluate the economic or financial viability of a project that is
under consideration. The analytical methods discussed include benefit cost
analysis (BCA), lifecycle cost analysis (LCA), cost effectiveness, savings to
investment ratio, the internal rate of return (IRR), the modified internal rate of
return (MIRR) 3 and the payback period.

4.1 Benefit Cost Analysis

The purpose of the BCA is to measure and compare the present value of the
benefits and the present value of the costs over a designated period of analysis for

3
Modified Internal Rate of Return is also known as Adjusted Internal Rate of Return (AIRR)
(Fisher et al).

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the proposed project. The results of the BCA are expressed as the NPV of the
proposed project as shown in equation (3). If the NPV is positive, implying that
present value of the benefits exceeds present value of the costs, the project could
be considered economically justified. In studies where multiple mutually
exclusive alternatives are being considered, the alternative with the greatest
positive NPV would be preferred from a strictly economic perspective.

The BCA results are sometimes presented in terms of a benefit-cost ratio (BCR).
A BCR is estimated by dividing the present value of the total benefits by the
present value of the total costs. If the BCR is >1 the project is considered
economically justified.

The BCR is sensitive to the definition of benefits and costs. It’s recognized that a
positive benefit can also be defined as a negative cost. This distinction makes a
difference in the calculation of the BCR in terms whether the positive benefit is
added to the numerator, or the negative cost is subtracted from the denominator.
For this reason the BCR is not the preferred method for presenting BCA results.

In theory BCA takes into account all monetary and non-monetary costs and
benefits that accrue to society. However in practice it is rarely possible to quantify
all of the costs and benefits. In some cases it may not be possible to quantify all
of the significant physical impacts of a proposed project or alternative. For
example it may not be possible to measure all the physical ecosystem changes
resulting from a proposed plan. In another example it is not possible to estimate
the spiritual value of resources. In these cases, the analyst could provide a
qualitative discussion of the potentially important impacts that cannot be
monetized and included in the BCA.

4.1.1 Lifecycle Cost Analysis

A LCA is a type of BCA that assesses the total cost of facility ownership. The
LCA 4 accounts for all the costs of ownership including construction, operation,
maintenance, and salvage value of a building or building system. A LCA adjusts
all costs to reflect the time value of money. When a LCA is applied to energy
conservation and renewable energy investments, the benefits to society are the
cost savings resulting from reduced energy usage and carbon emissions. The
equation used in a LCA for energy or water conservation measures as presented in
Handbook 135 is shown below.

4
Note a Life Cycle Evaluation or Analysis while a similar term is not considered a lifecycle
cost analysis. A Life Cycle Evaluation or Analysis evaluates the environmental consequences of
an activity or good from extraction to disposal and includes inventory, impact assessment, and
improvement analysis. A Life Cycle Evaluation or Analysis includes economic and social
components in addition to physical quantities.

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(6)

LCC = I + Repl – (+) Sal + E (W) + OM&R

Where:

LCC = Total life cycle cost in present value (PV) dollars

I = Present Value of Initial Cost of the energy conservation or
renewable energy component prior to actual use (year 0)
Repl = Present Value of capital replacement costs
Sal = Present Value of residual or salvage value of the energy
conservation measure at the end of the LCA period of analysis.
This value can be positive or negative
E(W) = Present Value of total energy cost or the Present Value of total
water costs
OM&R = Present Value of total operating, maintenance, and repair costs
which are distinctly tied to the energy conservation or renewable
energy component

The LCA can also be expressed in Net Savings (Equation 7). Net savings for a
retrofit project is found by subtracting the lifecycle costs based on the proposed
project from the life cycle costs generated in the absence of the proposed project
or baseline conditions. A project would be considered justified if the net savings
with respect to the base case is positive. When comparing multiple mutually
exclusive alternatives the alternative with the greatest positive net savings would
be preferred.

The formula for Net Savings is:

(7)

𝑁𝑒𝑡 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = 𝐿𝐶𝐶𝑏𝑎𝑠𝑒 𝑐𝑎𝑠𝑒 − 𝐿𝐶𝐶𝐴𝑙𝑡𝑒𝑟𝑛𝑎𝑡𝑖𝑣𝑒

Where:

LCC = Lifecycle Costs

4.2 Cost Effectiveness

A cost effectiveness analysis is distinctly different from a BCA. The economics
discipline has defined cost effectiveness as a method that seeks to identify the
least-cost way to achieve a given objective, without considering whether there is

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any economic justification for achieving that objective. Cost of effectiveness is

derived by dividing the total discounted costs by the physical output or service
that is generated by the project over the period of analysis.

The formula for a Cost Effectiveness Ratio is:

(8)
𝐶𝑡
∑𝑡=𝑛
𝑡=0
(1 + 𝑑) 𝑡
𝐶𝑜𝑠𝑡 𝐸𝑓𝑓𝑒𝑐𝑡𝑖𝑣𝑒𝑛𝑒𝑠𝑠 𝑅𝑎𝑡𝑖𝑜 =
𝑇𝑜𝑡𝑎𝑙 𝑂𝑢𝑡𝑝𝑢𝑡 𝑜𝑟 𝑆𝑒𝑟𝑣𝑖𝑐𝑒𝑠

Where:

Ct = Cost in each year

t = Year of occurrence (where 0 is the base date)
n = Number of years
d = Discount rate

A cost effectiveness analysis can be employed when the project or alternative’s

benefits cannot be expressed in monetary terms and therefore cannot be included
in a traditional BCA. In this case a cost effectiveness analysis provides a basis for
comparing project alternatives. A cost effectiveness analysis is sometimes used
when a level of service is mandated and thus the objective of the analysis is
to determine which program or alternative under consideration achieves the
mandated level at the lowest cost. When projects or alternatives are mandated it is
assumed that the economic benefits outweigh the costs. The limitation of a cost
effectiveness analysis is that the analysis does not provide the necessary
information to determine if project or alternative is economically justified.

4.3 Savings to Investment Ratio

The SIR, as defined in 10 CFR 436.2, is the ratio of the present value of net
savings to the present value of the net costs of an energy or water conservation
measure. The numerator is the present value of the net saving in energy or water
and no-fuel or non-water operations and maintenance cost attributable to the
proposed conservation measure. The denominator is the present value of the net
increase in investment and replacement costs less salvage value attributable to the
proposed conservation measure. An investment is considered justified if the SIR
is greater than zero, thus net savings are greater than zero.

The formula for SIR is:

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(9)

𝑆𝑡
∑𝑁
𝑡=0
(1 + 𝑑)𝑡
𝑆𝐼𝑅𝐴:𝐵𝐶 =
∆𝐼𝑡
∑𝑁
𝑡=0 (1 + 𝑑)𝑡

Where:

St = Savings in year t in operation costs attributable to the alternative

∆It = Additional investment related costs attributable to the alternative
t = Year of occurrence (where 0 is the base date)
d = Discount rate
N = Length of the study period

4.4 Internal Rate of Return

The IRR method is another analytic measure used to evaluate investment
alternatives. The IRR is the discount rate at which the NPV is equal to zero, as
illustrated in Equation (10). The IRR is the maximum rate that a project can pay
for the resources used for the project to recover its investment and operating costs
and still break even (Gittinger, 1982). A project is considered justified if the IRR
is greater than the discount rate established for the analysis.

(10)
𝑇
(𝐵𝑡 − 𝐶𝑡 )
𝑁𝑃𝑉 = � =0
(1 + 𝐼𝑅𝑅)𝑡
𝑡=0

The IRR method assumes that reinvested cash flows earn a rate or return exactly
equal to IRR. If this is not the case, this method may lead to the wrong
conclusions. The IRR method can also result in multiple results if the cash flows
alternate from positive to negative.

4.5 Modified Internal Rate of Return

As the name implies the MIRR is a modification of IRR that assumes the
reinvestment rate equals the cost of capital. The MIRR is the rate that equates the
project’s cost to the future value of all the net cash inflows (positive net cash
flows) at the end of the project life. The MIRR is compared against the discount
rate (the minimum acceptable rate of return) in the case of a federal investment
for energy conservation (10 CFR 436). If the MIRR is greater than the discount
rate the project is economically justified.

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The formula for MIRR is:

(11)
𝑇 −𝐹𝑉(𝑝𝑜𝑠_𝑐𝑎𝑠ℎ_𝑓𝑙𝑜𝑤, 𝑟𝑒𝑖𝑛𝑣𝑒𝑠𝑡𝑚𝑒𝑛𝑡 𝑟𝑎𝑡𝑒)
𝑀𝐼𝑅𝑅 = � −1
𝑃𝑉(𝑛𝑒𝑔_𝑐𝑎𝑠ℎ_𝑓𝑙𝑜𝑤𝑠, 𝑓𝑖𝑛𝑎𝑛𝑐𝑒 𝑟𝑎𝑡𝑒)

Where:

T = The number of equal periods at the end of which the cash

flows occur
pos_cash_flow = Positive net benefits of the project
neg_cash_flows = Negative net benefits of the project
reinvestment rate = Rate of return on reinvested profits
finance rate = Borrowing or loan rate

The MIRR formula requires a reinvestment rate and a finance rate. The
reinvestment rate could be calculated based on historic rate or the rates of recently
approved projects. The finance rate represents the cost of capital for the
organization.

4.6 Payback Period

The payback period is the time it takes to recover the initial investment based on
the earnings (savings) expected to result from the investment. The basic idea
behind the use of the payback period method is that the faster the initial
investment dollars are recouped the better the economics of the investment. An
alternative with a lower payback period is considered the better investment using
this method. The payback period can be calculated in two primary ways which
are often referred to as the simple payback period and the discounted payback
period.

The example below shows how a simple payback period is calculated for a stream
of uneven benefits and costs.

Year 0 1 2 3 4 5 6 7
Benefits ($) 0 300 300 300 300 300 300 300
Costs ($) 800 500 250 50 100
Net Benefits ($) -800 -200 50 300 250 300 200 300
Cumulative -800 -1,000 -950 -650 -400 -100 100 400
Benefits ($)

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(12)

Payback Period = Y + A/B

Where:

Y = The number years before the final payback year (5 years in the example
above)
A = Total remaining to be paid back at the start of payback year ($100 in the
example above)
B = Net Benefits in Payback Year ($200 in the example above).

The payback period in the example is 5.5 years.

The drawback of using the simple payback method is that it ignores the time value
of money. The discounted payback period is the generally accepted and preferred
method for calculating the payback period. The discounted payback period
method requires that cash flows occurring each year be discounted to the present
value, therefore accounting for the time value of money.

According to ASTM International (2013) (formerly known as American Society

for Testing and Materials) the discounted payback method finds the length of
time between the date of the initial project investment and the date when the
present value of the cumulative future earnings or savings, net of the cumulative
future costs, just equals the initial investment. The standard equation, accepted
by ASTM International, for the discounted payback period is shown in
Equation (13).

(13)
𝑃𝐵
(𝐵𝑡 − 𝐶�𝑡 )
𝐷𝑖𝑠𝑐𝑜𝑢𝑛𝑡 𝑃𝑎𝑦𝑏𝑎𝑐𝑘 𝑃𝑒𝑟𝑖𝑜𝑑 = � = 𝐶0
(1 + 𝑑)𝑡
𝑡=1

Where:

Bt = Dollar value of benefits in period t for the building or system being

evaluated less the benefits in period t for the mutually exclusive
alternative against which it is being compared.
𝐶̃ t = Dollar value of costs in period t for the building or system being
evaluated less the costs in period t for the mutually exclusive alternative
against which it is being compared.
C0 = Initial project investment cost as of the base time (year 0)
d = Discount rate
t = Time period t

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Both the simple and discounted payback period methods have several
shortcomings. The first shortcoming is that the payback method does not
consider the entire life of the project and ignores the savings after the payback
period. The following example demonstrates this point. Consider two
investments with the same initial costs ($10,000) and annual savings ($2,000).
The life of project A is 10 years, while the life of project B is 20 years. Both
project A and B would have equal payback periods but project B is expected to
provide earnings for an additional 10 years. Therefore project A is economically
inferior to project B.

The payback method often involves setting a maximum acceptable payback

period, which is usually subjective. For example suppose the maximum payback
period is 5 years. If Alternative A has a payback of 4 years and Alternative B has
a payback period of 20 years. Alternative A would be an acceptable investment.

5.0 TYPES OF CAPITAL INVESTMENT

DECISIONS AND PREFERRED ANALYSIS
METHOD
The LCA method along with the SIR and MIRR methods are mandated by
10 CFR 436A for analyses of energy conservation, water conservation, and
renewable energy measures in Federal buildings. The 10 CFR 436 recommends
that the payback period method be used as a rough screening tool to determine if a
more rigorous LCA should be employed.

The LCA is particularly useful for analyzing mutually exclusive conservation

investments that typically have higher initial costs but lower operating costs over
time. As discussed in the NIST Handbook 135, the lifecycle cost methodology is
well suited for a variety of decision types. These five general decision types are listed
below.

1. Accept or reject a project. An example of this type of decision is the

installation of storm windows or standard single pane windows.

2. Determine acceptable level of energy efficiency. A good example of this

type of decision is determining the optimal thermal resistance (R value) of
attic insulation.

3. Selecting between systems that provide the same level of service.

Selecting between a geothermal heat pump and a standard gas furnace is
an example of this type of decision.

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4. Determining the combination of interdependent systems or components.

This refers to selecting two or more building systems at the same time.
For example, selecting the type of heating system and the insulation
R values. For this type of decision, it’s recognized that the
implementation of one system will have effects on the energy savings
of the other.

5. Prioritization of independent projects. For this type of decision 10 CFR

436 requires the use of the SIR or the MIRR (referred to as AIRR in
10 CFR 436). In this case projects are ranked by SIR or MIRR and funded
in descending rank order.

6.0 LIFECYCLE ANALYSIS STEPS

This section describes the necessary steps for preforming a LCA. The steps are
listed below followed by brief descriptions of each step.

1. Develop project description

2. Collect annual cost data for various categories for two or more alternatives

3. Obtain the appropriate discount rate

4. Determine period of analysis

5. Compute the present value of costs incurred over the period of analysis for
each alternative

6. Sum present values of each alternative to find it’s lifecycle cost

7. Compare lifecycle costs for each alternative

8. Document the analysis

6.1 Project Description

The project description should define the purpose of the study, summarize the
alternatives, describe the services that will be provided by each alternative, and
identify the type of decision that the analysis will support. This information may
assist in determining the study’s data needs.

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6.2 Collect Lifecycle Cost Data

The estimated lifecycle costs are only as good as the data supporting them. Some
projects may be at a screening or cursory level while others may be supported by
detailed engineering designs and cost estimates. As designs and data are refined
over time the lifecycle cost analysis should be updated to reflect improved
estimates. Fortunately lifecycle costing software makes it simple to provide
updated results as design and cost data evolve. The LCA has very little
usefulness unless the lifecycle costs of the proposed alternatives are compared
against the lifecycle costs of the base case. Therefore it’s imperative that the
analyst collect the data and prepare the lifecycle costs for the proposed
alternatives and the base case.

Sunk costs related to investment and operations are also omitted. Sunk costs are
not considered because they are unrecoverable and will not be affected by the
decision to build or not build a project. Sunk costs as defined by 10 CFR 436 are
costs incurred prior to the time at which the lifecycle analysis occurs.

It is also important for the analyst to understand what year the costs are estimated
for and when they will occur in the study period timeframe. The cost or design
engineers typically identify the year in which the costs are estimated for. The
schedule of investment and operation costs can also be provided by the engineers.
It’s important to distinguish both single year costs and annually recurring costs.

6.2.1 Data Requirements

The specific data requirements for a Lifecycle Cost Analysis can be categorized
into two general categories; 1) investment related and 2) operations related.
Along with the costs, it’s also important to determine the year in which these
costs will occur. Table 3 summarizes these requirements. To provide a general
understanding of the data requirements a brief description is provided below.

Investment related costs include costs associated with engineering design,

purchase, and construction. Capital replacement and salvage value (resale or
disposal) costs are also investment related costs which are often overlooked.
Capital replacement costs depend on the system and estimated service life.
Salvage Value (resale or disposal) is the remaining value of the system at the end
of the study period. These are based on the resale value, scrap value, and any
disposal costs.

Operation costs relate to the long run operation of a building or system and
primarily include energy costs as well as maintenance and repair costs. Energy
conservation, water conservation, and renewable energy projects reduce energy
consumption and therefore long run costs for operation. Estimating energy and/or
water costs requires energy and/or water consumption or savings estimates for

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Table 3.—Summary of data requirements and potential sources

Data category Data input Source
Discount rate Energy Price Indices and Discount
Factors for Life-Cycle Cost Analysis,
Annual Supplement to NIST Handbook
Analysis 135 and NBS Special Publication 709
Study period 10 CFR 436A, subsequently modified
under the Energy Independence Security
Act 2007
Engineering and design costs Cost and design engineers often provide
Construction costs these estimates to the analyst. The
Investment Handbook 135 also suggests various cost
Capital replacement costs
estimating guides
Salvage value
Quantity of energy used Cost and design engineers often provide
these estimates to the analyst. The
estimates are made based on technical
specifications and computer simulation
Local energy prices Local utilities
Energy price escalation rates Energy Price Indices and Discount
Factors for Life-Cycle Cost Analysis,
Annual Supplement to NIST Handbook
135 and NBS Special Publication 709
Operation and maintenance Cost and design engineers often provide
these estimates to the analyst. The
estimates are made based on technical
specifications and computer simulation
Quantity of carbon generated Computer simulation, for example
Operations
Buildings Life Cycle Cost (BLCC) program
Price of carbon Energy Price Indices and Discount
Factors for Life-Cycle Cost Analysis,
Annual Supplement to NIST Handbook
135 and NBS Special Publication 709
Carbon price escalation rates Energy Price Indices and Discount
Factors for Life-Cycle Cost Analysis,
Annual Supplement to NIST Handbook
135 and NBS Special Publication 709
Water usage Cost and design engineers often provide
these estimates to the analyst. The
estimates are made based on technical
specifications and computer simulation
Water costs Local utility

both with and without the implementation the conservation measure for each
year in the study period. For example, what is the building’s energy use with
and without solar panels. This is primarily an engineering exercise based on
technical specifications and energy efficiency factors. For some conservation
measures, like solar panels, it’s important to include degradation factor if the

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efficiency over the life the product is expected to decline. A variety of

computer simulation models are available to compute energy savings with
and without project alternatives.

Energy or water usage is monetized using local energy prices. FEMP requires
the use of local energy or water prices in a LCA rather than regional or national
average prices. FEMP also requires that energy price escalation rates be used in
an LCA. As mentioned previously the energy price escalation rates are published
in the Annual Supplement to Handbook 135. There are no DOE water price
escalation rates.

Future carbon prices, considered an operational cost, should be considered in a

LCA analysis. In 2010 a series of tables projecting potential future carbon prices
and electricity related carbon emission rates under a range of carbon policy
scenarios were included in the Annual Supplement to Handbook 135. The
Annual Supplement of Handbook 135 relies on the EPA study entitled
Supplemental EPA Analysis of the American Clean Energy and Security Act
of 2009 to create these scenarios. Analysts would be wise to include a range of
carbon policy scenarios in an LCA.

Federal agencies are eligible for some state and utility level incentives. These
incentives are generally available as up-front incentives at the time of installation
or as performance based incentives paid out as the system generates power (Cory
et al. 2009). Incentives are generally not included in an economic analysis
because they are considered a transfer payment. Transfer payments represent a
shift of payments from one sector of society to another but do not change cost or
benefits from a national perspective. However, incentives may be included in a
financial analysis which is outside of the scope of this paper.

6.3 Determine Discount Rate and Study Period

Inputs related to analysis, also shown in table 3, primarily include discount rates
and study period. The discount rates for federal energy and water conservation
projects are determined annually by FEMP. These rates, as discussed previously
in Section 3.1, are published annually in the publication entitled “Energy Price
Indices and Discount Factors for Life-Cycle Cost Analysis, Annual Supplement to
NIST Handbook 135 and NBS Special Publication 709.”

The current maximum study period for a LCA was revised in Section 441 EISA
(2007) to 40 years. The study period, which is the length of time over which an
investment is analyzed, must be equal for all alternatives, depending on the
expected life of the project and/or the investor’s time horizon but cannot exceed
40 years.

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6.4 Preparing the Lifecycle Cost Comparison and

Results
Recall the LCA measures the present value of the cost of owning, operating and
maintaining over its useful life (including its fuel and water, energy, labor and
replacement components), and disposing of the building system(s) over a
given study period. Once the cost data is collected by year for each
alternative and a discount rate and study period are determined the lifecycle
costs can be calculated, using Equation (6). The alternative with the lowest
lifecycle cost, greater than zero, is the preferred alternative. If the
estimate lifecycle costs are negative the project or alternative is not considered
justified.

Recall that the LCA can also be expressed in Net Savings (Equation 7). A project
would be considered justified if the net savings with respect to the base case is
positive. When comparing multiple mutually exclusive alternatives the
alternative with the greatest positive net savings would be preferred.

6.5 Documenting the Analysis

Detailed documentation for a LCA should be an important requirement for all
studies. Careful documentation is necessary for a decision record. Detailed
documentation also allows for easy review of the inputs which is necessary for
accuracy or future updates. Handbook 135 provides a list of suggested items to
be documented in a LCA report, which is reproduced below in table 4.

7.0 TOOLS FOR CONDUCTING LCA

A LCA can be conducted using a variety of tools. Three possible tools are
discussed below.

7.1 Spreadsheet
A simple spreadsheet can be developed by an analyst who is knowledgeable of
the LCA methodology and the requirements set out in 10 CFR 436. Built into a
spreadsheet, such as Microsoft Excel, are all the necessary functions/formulas to
conduct a LCA and supplementary measures such as MIRR. A spreadsheet is
powerful and readily available tool however the analyst must have the proper
training and background in order to properly set up a spreadsheet application.

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Table 4.—Recommended documentation items for a lifecycle cost analysis report

General information Discounting
Type of decision to be Computation of
made lifecycle costs
1. Project description 5. Computations
Constraints Computations of
supplementary
measures
Technical description Results of LCC
comparison
Rationale for including Uncertainty
6. Interpretation
them assessment
2. Alternatives
Non-monetary Results of sensitivity
considerations analysis
7. Non-monetary Description of
savings/costs intangibles
Study period 8. Other Narrative
considerations
Base date 9. Recommendations
Service date
Discount rate
3. Common
parameters Treatment of inflation
Operational
assumptions
Energy and water
price schedules

Investment related
costs
Operating related
costs
4. Cost data and Energy usage
related factors amounts and type
Timing of costs
Cost data sources
Uncertainty
assessment
Source: NIST Handbook 135.

7.2 SAM
A better approach to conduct a LCA would be to use a tool specifically developed
for analyzing energy and water conservation and renewable energy projects. The
National Renewable Energy Lab has tool call System Advisor Model (SAM)
available for LCA analyses. In addition to the LCA analysis SAM also includes a
performance model which calculates an alternatives energy output on an hourly basis
(sub-hourly simulations are available for some technologies). The drawback of

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this tool is that is not specifically built for federal analyses so it would require
more knowledge of the federal requirements and methodology described in
10 CFR 436.

7.3 BLCC5
The tool that is recommended for a LCA related to federal energy and water
conservation and renewable energy is called the Building Lifecycle Cost Program
(BLCC5) (Peterson, 1995). NIST developed BLCC5 under the sponsorship of
FEMP. The program has been in use since the 1970's to evaluate building related
energy and water conservation projects and renewable energy projects according
to 10 CFR 436. The program is updated annually to include the current discount
rates and energy price indices found in the Annual Supplement to the NIST
Handbook 135. The BLCC5 program calculates the lifecycle costs in terms of net
savings, and calculates other measures such as SIR, MIRR, and the payback
period.

BLCC5 also estimates emissions reductions (CO2, SO2, and NOx). Unfortunately
the current version of BLCC5 does not monetize carbon savings for renewable
energy alternatives. An analyst can easily monetize these values, for inclusion in
the LCA outside the model using a spreadsheet application. Specifically the
carbon savings can be monetized, in a spreadsheet, by combining the physical
estimates (in kilograms) provided by BLCC5 and the Carbon prices and indices
provided in the Annual Supplement to Handbook 135, Tables D-1 and D-2,
respectively.

8.0 OTHER NON-ECONOMIC DECISION

MAKING CONSIDERATIONS
This paper focused on conducting the economic analysis of federal investments
related energy and water conservation measures. However, there may be non-
economic decision criteria that influence the decision to adopt energy and water
conservation measures. It’s also recognized that it may not be possible to
quantify all the project benefits and costs. Handbook 135 suggests documenting
any non-economic considerations in the LCA report.

The decision criteria must comply with the related statues, regulations, and
executive orders as well the agency’s policy and related directives and standards.
Decisions regarding all federal investments must be integrated with the agency’s
mission and budgeting process.

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Other non-economic decision making considerations that could influence the

decision to adopt energy and water conservation measures include:

• Achieve agency goals and targets for greenhouse gas reduction and
renewable energy

• Mitigate the agency’s risk and vulnerabilities related to climate change

• Increase the use of renewable energy

• Hedge against future power price increases

• Improving or maintaining the agency’s public perception

• Extending current energy and water supplies

• Altruism

9.0 RECOMMENDATIONS
A few recommendations for Reclamation staff responsible for conducting or
overseeing economic analyses related to energy and water conservation and
renewable investments in new and existing federally owned or leased buildings
are highlighted below.

1. An understanding of the methodology for LCA as outlined in 10 CFR 436

is recommended before implementing LCA analyses.

2. Familiarity with legislation, rulemakings, and executive orders related to

the use of LCA methodology, especially NIST Handbook 135 and the
annual supplement to Handbook 135 will be useful.

3. Analysts should consider adopting the use of BLCC program for LCA of
federal investments related to energy and water conservations measures.

4. A detailed documentation of inputs, including source information, and

results as described in NIST Handbook 135 should be required.

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GLOSSARY
Base Case: The building system against which an alternative building system is
compared.

Base Year: Year 0 of the Study Period.

Constant Dollars: Dollars of uniform purchasing power tied to a reference year

(usually the base year) and exclusive of general price of inflation or deflation.

Cost of Capital: The rate of return that capital could be expected to earn in an
alternative investment of equivalent risk.

Current Dollars: Dollars of non-uniform purchasing power, including general

price inflation or deflation, in which actual prices are stated.

Discount Rate: The rate at which future benefits and costs are discounted.

Nominal Discount Rate: The rate reflecting the time value of money stemming
from both inflation and the real earning power of money over time.

Mutually Exclusive Projects: Projects where the acceptance of one precludes

acceptance of the others.

Present Value: The time equivalent of past, present, or future Cash Flows as of
the beginning of the Base Year.

Real Discount Rate: The rate of interest reflecting the portion of time value of
money attributable to the real earning power of money over time and not to
general price inflation.

Replacement Cost: Capital cost for replacing a system component during the
Study Period.

Residual Value: The estimated value, net of any Disposal Costs, of any building
or building system removed or replaced during the Study Period, or remaining at
the end of the Study Period, or recovered through the resale or reuse at the end of
the Study Period.

Study Period: The length of time period covered by the economic evaluation.

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REFERENCES
ASTM International, “Standard Practice for Measuring Payback for Investments
in Buildings and Building Systems,” Designation: E1121-12. 2013.

Bureau of Reclamation (Reclamation). 2012. “Interpretation of the Guiding

Principles for Federal Leadership in High Performance and Sustainable
Buildings – Existing Buildings,” U.S. Department of the Interior, Bureau
of Reclamation, Policy and Administration, Denver, Colorado, July 2012.

Code of Federal Regulations, 10 CFR 436, Subpart A, Federal Energy

Management and Planning Programs: Life Cycle Cost Methodology and
Procedures, effective December 20, 1990.

Cory, Karlynn, Charles Coggeshall, Jason Coughlin, and Claire Kreycik. 2009.
Solar Photovaltaic Financing: Deployment by Federal Government
Agencies. NREL/TP- 6A2-46397, National Renewable Energy
Laboratory, U.S. Department of Energy, Golden, CO.

Fisher, Jeffrey D., Robert S. Martin, and Paige Mosbough. “The Language of
Real Estate Appraisal,” Dearborn Financial Publishing Inc., 1991.

Fuller, Seiglinde K. and Stephen R. Petersen. 1995. NIST Handbook 135, Life-
Cycle Costing Manual for the Federal Energy Management Program,
National Institute of Standards and Technology Building and Fire
Research Laboratory, Office of Applied Economics, Gaithersburg, MD.

Gittinger, J. Price. “Economic Analysis of Agricultural Projects,” The John

Hopkins Press, 1982.

Haase, Scott., Kari Burman, Douglas Dahle, Donna Heimiller, Tony Jimenez,
Jenny Melius, Blaise Stoltenberg, and Otto VanGeet. 2013. Case Studies
of Potential Facility-Scale and Utility-Scale Non-Hydro Renewable
Energy Projects across Reclamation, National Renewable Energy
Laboratory, U.S. Department of Energy, Office of Energy Efficiency &
Renewable Energy, Golden, CO.

Petersen, Stephen R,. 1995. BLCC5, The National Institute of Standards and
Technology “Building Life-Cycle Cost” Program, NISTIR 5185-2,
National Institute of Standards and Technology, Gaithersburg, MD.

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The Basics of Lifecycle Cost Analyses Supporting
Reclamation’s Sustainable Energy Goals

Rushing, Amy S., Joshua D. Kneifel, and Barbara C. Lippiatt. 2012. (revised
annually). Annual Supplement to National Institute of Standards and
Technology Handbook 135 and SP 709, Energy Price Indices and
Discount Factors for Life-Cycle Analysis, NISTIR 85-3273-27, NIST,
Gaithersburg, MD.

U.S. Environmental Protection Agency, Supplemental EPA Analysis of the

American Clean Energy and Security Act of 2009: H.R. 2454 in the 111th
Congress, Office of Atmospheric Programs, January 29, 2010.

U.S. Office of Management Budget, Circular No. A-94, Guidelines and Discount
Rates for Benefit-Cost Analysis of Federal Programs, Transmittal Memo
No. 64, October 29, 1992.
http://www.whitehouse.gov/omb/circulars_a094/

U.S. Water Resources Council. 1983. Economic and Environmental Principles

and Guidelines for Water and Related Land Resources Implementation
Studies. Washington, D.C.: U.S. Government Printing Office.

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APPENDIX A
NREL Report Review

113
The National Renewable Energy Lab (NREL conducted an assessment of
Photovoltaic (PV) solar arrays for two Reclamation offices; Willows and Lake
Berryessa for Reclamation’s Research and Development office (Hasse et al,
2013). Reclamation’s Economics, Planning, and Technical Communications
Group, (86-68270) was asked by Reclamation’s Research and Development office
to review the economic evaluation and prepare comments. The purpose of the
assessment is to provide an engineering and economic evaluation of these facility
scale solar applications.

It should be noted that NREL’s analysis was conducted to provide illustrative

examples of how a N-HRE assessment is conducted and the potential that exists
and demonstrate how incentives apply to the Federal government. The following
comments are provided to emphasize the required detail necessary for future
analyses.

NREL REPORT ANALYSIS OF ECONOMIC

EVALUATION
Overall the assessment emphasized the engineering aspects of the solar
applications but the economic evaluation lacked detail and documentation.
Therefore it was difficult to determine if the federal guidelines for analyzing the
economic cost effectiveness were followed.

The NREL evaluation employed the payback method to evaluate the Willows and
Lake Berryessa applications. In future analysis, the report should indicate
whether a simple payback period or a discounted payback was used. Also, it is
recommended that an LCCA be prepared rather than a payback analysis because
payback method does not consider the entire life of the project and ignores the
savings after the payback period. Also, the payback method often involves setting
a maximum acceptable payback period, which is subjective. Finally, the payback
method ignores the time value of money unless the discounted payback period
method was employed.
A life cycle analysis does require a few more inputs but can used to quickly
compare the solar applications to baseline or status quo alternatives and provides
decision makers with a less subjective analysis.
Generally the input data employed in the NREL economic analysis was difficult
to determine or evaluate. For example, the source of the price of electricity was
not documented. It’s also unclear if the price of electricity is for residential or
commercial customers. Through discussions with NREL’s staff many of the input
questions (what was used and/or data source) were answered. However the
analysis would benefit from a detailed careful documentation of the data
assumptions including the data sources. It’s recommended that future
documentation follow the recommendations made in Handbook 135.

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Also, the NREL evaluation would be more meaningful if several inputs were
included in the analysis. First, NREL’s analysis assumed static energy cost rather
than using the escalation factors supplied in the Annual Supplement to
Handbook 135. Second, the analysis assumed no replacements costs. And
finally, future carbon price were not considered.

In summary, the recommendations to improve future economic analysis are listed

below.

• Use a Lifecycle Cost analysis method

• Adopt the use of the BLCC tool

• Carefully document assumptions and data as described in Handbook 135

• Document each component of the installation costs

• Include replacements costs necessary for a PV system

• Include maintenance costs, if $0 document this assumption

• Include salvage values, if $0 document this assumption

• Include energy price escalation factors provided in the Annual

Supplement to the Handbook 135

• Include future carbon prices and policy scenarios using the data
provided by BLCC and the Annual Supplement to the Handbook 135

• Consider future panel efficiency by adopting a panel degradation factor

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APPENDIX B
LCA Example Using Building Lifecycle Cost Software

116
This appendix presents an example of a lifecycle cost analysis, employing the
BLCC5 software. A lifecycle cost analysis is an economic benefit cost analysis
which determines if a proposed project is economically justified. An economic
benefit cost analysis attempts to consider all project benefits and cost and
determines if a project is justified from a national or societal perspective. It’s
appropriate for federal agencies to conduct an economic analysis versus a
financial analysis because a federal agency must compare projects or alternatives
from a broader national perspective. A financial analysis is narrowly focused on
determining if the beneficiaries of the project be financially better compared to
the project costs.

The example shows the suggested method for which a lifecycle cost analysis is
documented and reported. Recognize that each analysis is unique and may
require other reporting requirements and categories. It should be noted that some
of the data inputs were assumed for the purpose of this example. Every attempt
was made to use the assumptions from the NREL report (Hasse et al. 2013)
related to the photovoltaic (PV) system application at Lake Berryessa. However
some of the data necessary for an LCC analysis were not available in this report
so assumptions were made without technical validation. Therefore the results are
not to be used for decision making purposes.

BLCC EXAMPLE
The Bureau of Reclamation (Reclamation) Lake Berryessa Field Office is located
in Napa, California. The Lake Berryessa field office is part of the Reclamation’s
Mid Pacific Region, Central California Area Office. The Lake Berryessa office is
connected to the Pacific Gas and Electric Company (PG&E). The purpose of this
study is to conduct a lifecycle cost analysis for the Lake Berryessa Office Area 1
(Hasse et al. 2013) PV system compared to the baseline conditions.

PROJECT DESCRIPTION
For the purpose of this analysis two alternatives were analyzed; Status Quo
(Alternative 1) and a 2) PV system application (Alternative 2). Alternative 1
assumes that the Lake Berryessa office energy needs will be met by PG&E.
Alternative 2 assumes that some of the Lake Berryessa Office’s energy needs
would be offset by a PV system, equal to the amount produced by the solar array
(76,957 kWh annually). The engineering data and site analysis are explained in
the NREL report (Hasse et al. 2013).

The purpose of this analysis is to compute the lifecycle costs for each alternative.
In this example Alternative 1 serves as the baseline against which Alternative 2
will be compared. The type of decision this research will support is determining

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the cost effectiveness, using a lifecycle analysis, and therefore whether
Alternative 2 should be accepted as compared to Alternative 1, status quo
operations.

It should be noted that the data used in this analysis is on a cursory level,
therefore the lifecycle cost results should only be used for screening purposes. As
design and cost data evolve the lifecycle analysis should be updated using the
more refined data.

The parameters and assumptions common to both Alternative 1 and Alternative 2

are shown in Table B-1 below.

Table B-1.—Common assumptions for alternatives

Assumption Description Source
Location Lake Berryessa Field Office, Napa, NREL Report
California
Rationale for The office is favorably located for NREL Report
including the PV systems since the highest rates
alternatives are mid-day during the summer
when PV output is maximum
Type of Determine the economic cost NREL Report
decision to be effectiveness using a lifecycle cost
made analysis of a grid connect solar
application compared to baseline
conditions
Technical The area office manager desires to NREL report
description analyze a PV solar array to offset
office energy requirements.
1
Constraints Many data inputs were not Assumed
researched or verified therefore
these results are only for the
purpose of providing an example of
an lifecycle cost analysis using
BLCC5
Computation Lifecycle cost analysis NA
method
Computation of BLCC5 model NA
lifecycle costs
Computations Net savings is also presented NA
of
supplementary
measures
1
Non-monetary None Assumed
considerations
Useful life of 25 years NREL Report
systems
Energy price $0.15 kWh NREL Report
Study period 25 years NREL Report

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Table B-1.—Common assumptions for alternatives
Assumption Description Source
Treatment of Discounts rates are real exclusive Handbook 135 recommendation
inflation of general inflation for federal appropriations
1
Operational None Assumed
assumptions
Discount Rate 3 percent 2012 Annual Supplement to
Handbook 135
Energy Price escalation factors 2012 Annual Supplement to
escalation incorporated in BLCC5. Note that Handbook 135, Tables Cb-1-5.
these are real rates exclusive of
general inflation.
1
Assumed indicates there was insufficient data in the NREL report to determine.

Alternative 1: Status Quo Data Assumptions

Alternative 1 assumes status quo operations of the Lake Berryessa office. The
relevant data and the timing of the cost data for this alternative are shown in the
table B-2 below.

Table B-2.—Alternative 1 data assumptions

Timing of
Data category Assumption cost Source
1
Baseline Alternative: $0 NA Assumed
Investment related
costs
1
Baseline Alternative: $0 NA Assumed
Operational related
Costs
1
Baseline Alternative: $0 NA Assumed
Replacement Costs
Baseline Alternative: 182,080 kWh Annually NREL report
Energy Usage
Baseline Alternative: $0.17 kWh NA NREL report
Energy Price
Baseline Alternative: 0 NA NREL report
Solar Savings
1
Uncertainty Data were assumed and NA Assumed
Assessment was not technically
verified for the purpose of
this example. Decisions
should not be based on
these data
1
Assumed indicates there was insufficient data in the NREL report to determine.

B-3
119
Alternative 2: PV System Application Data Assumptions
Alternative 2 assumes that a PV system will be installed at the Lake Berryessa
office. The PV system will offset 76,957 kWh of the building’s annual energy
usage (182,080 kWh). The relevant data assumptions for this alternative are
shown in the table B-3 below.

Table B-3.—Alternative 2 data assumptions

Timing of
Data category Assumption cost Source
1
Solar alternative: $462 Annually NREL report
operating related costs
Solar alternative: 182,080 kWh Annually NREL report
energy usage amounts annually
Solar alternative: $0.17 per kWh NA NREL report
energy price
Solar alternative: 76,957 kWh Annually NREL report (as
2
energy savings estimated by PV Watts)
1
Solar alternative: Inverters, at Every Assumed
replacement costs $5000 15 years
1
Solar alternative: $0 NA Assumed
2
incentives/rebates
1
Assumed indicates there was insufficient data in the NREL report to determine.
2
The NREL included some performance based incentives these were not included in
the economic analysis because they are considered transfer payments.

It should be noted that the NREL report included some performance based
incentives these were not included in this economic analysis. Incentives are
generally not included in an economic analysis because they are considered a
transfer payment. Transfer payments represent a shift of payments from one
sector of society to another but do not change cost or benefits from a national
perspective. However, incentives may be included in a financial analysis, which
is outside of the scope of this paper.

Analysis Methods
The data assumptions presented in table B-3 were entered into BLCC5 to
calculate the lifecycle costs of each alternative. Carbon effects were calculated
outside of BLCC5 in a spreadsheet. BLCC5 estimates the quantity of emissions
in kilograms as shown in table B-4. The information in table B-4 were combined
with the Project Carbon Dioxide emissions prices and the projected carbon

B-4
120
 Table B-4.—Emissions reduction summary

Average Annual Emissions Life-cycle

base case alternative reduction reduction
Energy type (kg) (kg) (kg) (kg)
Electricity
CO2 47,875 27,641 20,234 505,801
SO2 11.8 6.81 4.99 124.67
NOx 19.67 11.35 8.32 207.78
Source: BLCC5.

dioxide emissions rates of escalation found in the 2012 Annual Supplement of

Handbook 135 Tables D-1 and D-2 respectively to estimate the annual benefit of
carbon emissions for the solar alternative. The present value of this benefit was
added to the present value of the lifecycle costs estimates from BLCC5 to
estimate the Present Value Life-Cycle-Costs.

For the purpose of this analysis 3 carbon policy scenarios were chosen: (1) no
policy, (2) low pricing, and (3) high pricing. These scenarios are consistent with
the data present in 2012 Annual Supplement of Handbook 135. The Annual
Supplement of Handbook 135 relies on the EPA study entitled Supplemental EPA
Analysis of the American Clean Energy and Security Act of 2009 to create these
scenarios. The Low Pricing scenario assumes that developing countries do not
take any action over the next 40 years to restrict carbon emissions. The High
Pricing scenario assumes that carbon offsets from other countries are not allowed
and nuclear and biomass capacity construction is restricted.

ANALYSIS RESULTS
Based on this analysis the present value of the lifecycle costs for the solar
alternative are greater than those of the baseline alternative. Therefore the solar
alternative is not lifecycle cost effective. The Net Savings for Alternative 2 is
negative also indicating the alternative is not cost effective. The recommendation
to the decision maker based on these results would be to continue with the status
quo alternative assuming that economics is the only consideration. The agency
may consider other factors to move forward with this project such as:

• Achieve agency goals and targets for greenhouse gas reduction and
renewable enrgy

• Mitigate the agency’s risk and vulnerabilities related to climate change

• Increase the use of renewable energy

B-5
121
 • Hedge against future power price increases

• Improving or maintaining the agency’s public perception

• Extending current energy and water supplies

• Altruism

Again, the purpose of showing these results is purely to show an example of a

lifecycle cost analysis using BLCC5. These results are shown in table B-5.

B-6
122
Table B-5.—Comparison of present value life-cycle-costs
Alternative Net savings

Low High No Low High No

emission emission emission emission emission emission
Base case policy policy policy policy policy policy

Initial investment costs:

Capital requirements as of base date $0 $271,550 $271,550 $271,550 ($271,550) ($271,550) ($271,550)
Future costs:

Energy consumption costs $471,713 $272,341 $272,341 $271,341 $199,372 $199,372 $199,372

Energy demand charges $0 $0 $0 $0 $0 $0 $0

Energy utility rebates $0 $0 $0 $0 $0 $0 $0

Water costs $0 $0 $0 $0 $0 $0 $0

Recurring and non-recurring OM&R costs $0 $8,046 $8,046 $8,046 ($8,046) ($8,046) ($8,046)
Capital replacements $0 $3,210 $3,210 $3,210 ($3,210) ($3,210) ($3,210)

Residual value at end of study period $0 $0 $0 $0 $0 $0 $0

Subtotal (for future cost items) $471,713 $555,147 $555,147 $555,147 ($83,434) ($83,434) ($83,434)

CO2 emissions benefit $0.00 $5,042.78 $22,734.38 $0 $5,042.78 $22,754.38 $0.00

Total PV life-cycle cost $471,713 $560,190 $577,901 $555,147 ($78,391) ($60,680) ($83,434)

B-7
123
 Appendix J. National Alliance of Preservation Commissions –
Sample Guidelines for Solar Systems in Historic Districts,
National Park Service – Incorporating Solar Panels in
Rehabilitation Project

124

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
 National Alliance of Preservation Commissions
Sample Guidelines
for Solar Systems
in Historic Districts

The rapidly growing trend toward retrofitting

homes to be more energy efficient has brought an in-
crease in the number of applications for installing solar
energy systems on buildings within locally designated
historic districts. The increase in solar systems applications in re-
cent years has prompted numerous local preservation commissions to
hastily develop guidelines for them with varying degrees of success.

The following Sample Guidelines for Solar Systems for Locally Desig-
nated Historic Properties were developed in 2009 by Kimberly Kooles,
NAPC support staff and revised by Caty Rushing in 2011. They are
intended to serve as a starting point for local preservation commissions
developing their own guidelines for solar systems.

NAPC • P.O. BOX 1605 • ATHENS, GA 30603 • 706-542-4731

“Helping local preservation commissions succeed through educa-
tion, advocacy, and training”
Types of Systems:
• Photovoltaic
A photovoltaic system (or PV system) is
a system which uses one or more solar
panels to convert sunlight into electricity.
It consists of multiple components, includ-
ing the photovoltaic modules, mechanical
and electrical connections and mountings
and means of regulating and/or modifying
the electrical output.

• Solar Shingles
Solar shingles, also called photovoltaic
shingles, are solar cells designed to look
like conventional asphalt shingles. There
are several varieties of solar shingles,
including shingle-sized solid panels that
take the place of a number of conventional
shingles in a strip, semi-rigid designs
containing several silicon solar cells that
are sized more like conventional shingles,
and newer systems using various thin film
solar cell technologies that match conven-
tional shingles both in size and flexibility

• Freestanding
Freestanding PV panels or freestanding
arrays allow the benefits of renewable solar
power without disrupting the roofline or
altering the house. They are placed away
from the residence and connected through
an undergroud wiring. When a roof may
be blocked by trees or not recieving direct
sunlight, the mobillity of a freestanding
panel allows the ability to move into opti-
mal sunlight areas that may change sea-
sonally.

• Standalone
Sample Guidelines for Solar Systems for
Locally Designated Historic Projects

When planning the installation of solar panels the overall objec-

tive is to preserve character-defining features and historic fabric
while accommodating the need for solar access to the greatest
extent possible. All solar panel installations must be considered
on a case by case basis recognizing that the best option will de-
pend on the characteristics of the property under consideration.
Some guidelines apply to virtually all installation options and are
repeated in each section.

All solar panel installations should conform to the Secretary of

the Interior’s Standards for Rehabilitation.
Applicable Standards are:

Standard Two: The historic char- Standard Nine: New additions,

acter of a property shall be retained and exterior alterations, or related new
preserved. The removal of historic mate- construction shall not destroy historic
rials or alteration of features and spaces materials that characterize the property.
that characterize a property shall be The new work shall be differentiated
avoided. from the old and shall be compatible
with the massing, size, scale, and archi-
tectural features to protect the historic
integrity of the property and its envi-
ronment.
1 Primary Elevations
For most properties, locating solar panels on
the primary facade is the least desirable op-
tion because it will have the greatest adverse
effect on the property’s character defining fea-
tures. All other options should be thoroughly
explored.
• Utilization of low-profile solar panels is
recommended. Solar shingles laminates,
glazing, or similar materials should not
replace original or historic materials. Use
of solar systems in windows or on walls,
siding, and shutters should be avoided.

• Panels should be installed flat and not

These solar panels low profile and location make them
alter the slope of the roof. Installation unobtrusive even though they are visible from the public
of panels must be reversible and not right of way. Photo by Paul Trudeau
damage to the historic integrity of the
resource and district.

• Solar panels should be positioned behind existing architectural features such as

parapets, dormers, and chimneys to limit their visibility.

• Use solar panels and mounting systems that are compatible in color to established
roof materials. Mechanical equipment associated with the photovoltaic system
should be treated to be as unobtrusive as possible.

2 Secondary Elevations
• Solar panels should be installed on rear slopes or other locations not easily visible from
the public right-of-way. Panels should be installed flat and not alter the slope of the roof.
Installation of panels must be reversible and not damage the historic integrity of the
resource and district.

• Flat roof structures should have solar panels set back from the roof edge to minimize
visibility. Pitch and elevation should be adjusted to reduce visibility from public right-of-
way.

• Solar panels should be positioned behind existing architectural features such as parapets,
dormers, and chimneys to limit their visibility.
2 Secondary Elevations (Continued)
• Use solar panels and mounting systems that are compatible in color to
established roof materials. Mechanical equipment associated with the solar
panel system should be painted or treated to be as unobtrusive as possible

• Use of solar systems in non-historic windows or on walls, siding, or shut-

ters should be installed as to limit visibility from the public right of way.

3 Historic Accessory Structures

• Solar panels should be installed on rear
slopes or other locations not highly visible
from the public right-of-way. Panels should
be installed flat and not alter the slope of the
roof. Installation of panels must be reversible
and not damage the historic integrity of the
resource and district.

• Flat roof structures should have solar panel

installations set back from the roof edge
to minimize visibility. Pitch and elevation
should be adjusted to reduce visibility from
public right-of-way.
Solar panels placed on an accessory structure not vis-
ible from the public right of way should still follow the
• Solar panel installations should be posi-
slope of the roof and have a low profile. Photo courtesy tioned behind existing architectural features
of Dan Corson such as parapets, dormers, and chimneys to
limit their visibility.

• Use solar panels and mounting systems that are compatible in color to the property’s roof
materials. Mechanical equipment associated with the photovoltaic system should be as un-
obtrusive as possible.

• Use of solar systems in non-historic windows or on walls, siding and shutters should be
installed as to limit visibility from the public right of way.
4 Freestanding or Detachedte
• Freestanding or detached on-site
solar panels should be installed
in locations that minimize visibil-
ity from the public right of way.
These systems should be screened
from the public right of way with
materials elsewhere in the district
such as fencing or vegetation of
suitable scale for the district and
setting.

• Placement and design should not

detract from the historic charac- Freestanding solar panels should be installed in loca-
tions that minimize visibility from the public right of
ter of the site or destroy historic
way.
landscape materials.
Consideration to the visibility of solar panels from neighboring properties should be taken, without in-
fringing upon the required solar access.

5 New Construction On-Site-

• Solar panels should be integrated into the initial design of new construction or infill projects,
when possible, to assure cohesion of design within a historic context.

• Solar panels should be installed on rear slopes or other locations not highly visible from the
public right of way whenever possible. Panels should be installed flat and not alter the slope
of the roof.

• Flat roof structures should have solar panels set back from the roof edge to minimize visibil-
ity. Pitch and elevation should be adjusted to reduce visibility from the public right-of-way.

• Use solar panels and mounting systems that are compatible in color to established roof mate-
rials. Mechanical equipment associated with the solar panel system should be treated to be as
unobtrusive as possible.

• Use of solar systems in windows or on walls, siding, or shutters should be installed with lim-
ited visibility from the public right-of-way.
 Not Recommended for Any Reason
• Removal of historic roofing materials during the installation of solar
systems.
• Removing or otherwise altering historic roof configuration – dormers,
chimneys, or other features – to add solar systems.
• Any other installation procedure that will cause irreversible changes to
historic features or materials.

When considering retrofitting measures, historic building owners should

keep in mind that there are no permanent solutions. One can only meet the
standards being applied today with today's materials and techniques. In the
future, it is likely that the standards and the technologies will change and
a whole new retrofitting plan may be necessary. Thus, owners of historic
buildings should limit retrofitting measures to those that achieve reasonable
energy savings, at reasonable costs, with the least intrusion or impact on the
character of the building.

(National Park Service. Preservation Brief 3: Conserving Energy in Historic Buildings. Available from http://
www.nps.gov/history/hps/TPS/briefs/brief03.htm#Preservation%20Retrofitting. Accessed on August 10, 2009.)

“Helping local preservation commissions succeed

through education, advocacy, and training”

NAPC • P.O. BOX 1605 • ATHENS, GA 30603 •

706-369-5881
National Park Service
U.S. Department of the Interior
Technical Preservation Services

Interpreting
N
ITS52
UMBER
The Secretary of the Interior’s Standards for Rehabilitation

Subject: Incorporating Solar Panels in a Rehabilitation Project

Applicable Standards: 2. Retention of Historic Character
9. Compatible Additions/Exterior Alterations

Issue: Enhancing the energy efficiency of a historic building is important. To that end, it is often possible to install features
such as solar panels and photovoltaic cells provided they are installed in a sensitive manner. Because these elements must be
positioned to take advantage of unobstructed sunlight, the roof of a historic structure is an obvious location. The roofline of a
historic building is often a distinctive feature. Therefore, the installation of solar panels should conform to guidance regarding
rooftop additions, i.e. that they be minimally visible, to avoid altering the historic character of the building. Historic buildings
with a flat roof or parapet can usually accommodate solar panels because the panels will be hidden, while properties with
a hipped or gabled roof are generally not good candidates for a rooftop solar installation. Solar panels on historic buildings
should not be visible from the public right of way such as nearby streets, sidewalks or other public spaces.

In circumstances where solar collectors are not placed on rooftops, they should only be positioned in limited or no-visibility
locations in secondary areas of the property. Vegetation or a compatible screen may also be an option to further reduce the
impact of these features on a historic property. For some historic buildings, it may not be possible to incorporate solar panels
and meet the Secretary of the Interior’s Standards for Rehabilitation.

Application 1 (Compatible treatment): solar panels

The rehabilitation of this mid-nineteenth
century mill incorporated a large, roof-
mounted photovoltaic installation.
Although the historic building does not
have a parapet wall at the roofline, the
height of the building and the arrangement
of the panels render the entire installation
invisible from the ground. It is important
Because of the size of this historic mill, a large array of solar panels could be installed on
to note that the panels are placed the flat roof without being seen from the ground.
horizontally. Had the panels been installed
with a vertical tilt, the angle required to maximize efficiency would have caused the panels to extend significantly higher
above the roof. Simply changing the direction in which the panels are tilted can affect their visibility and reduce their impact
on the character of the historic property.

By placing the panels horizontally, the overall height

Solar panels installed on the flat roof. of the installation and its visibility is reduced.

ALTERNATIVE ENERGY
Application 2 (Incompatible treatment): During the rehabilitation of this late-nineteenth century commercial building, a
conspicuous rooftop monitor with prominent solar panels and skylights was constructed on the one-story structure. The size
and finish of this rooftop addition are incompatible with the historic character of the building. However, the building could
have accommodated both skylights and solar panels if they had been installed differently. An alternative design that could
have met the Standards would have included low-profile skylights and solar panels concealed behind the parapet wall.

The addition of a large rooftop monitor featuring skylights on the front slope and solar panels on the rear slope is not compatible with the
historic character of this small, one-story commercial building.

Application 3 (Compatible treatment): The rehabilitation of this historic

post office incorporated solar panels as dual-function features: generation
of electricity and shading for south-facing windows. In this instance, the
southern elevation of the building is also a secondary elevation with limited
visibility from the public right of way. Additionally, because this area of the
building is immediately next to the post office’s loading dock, it has a more
utilitarian character than the primary facades and, therefore, can better
accommodate solar panels. Because the panels are in a suitable location at
the rear of the property and are appropriately sized to serve as awnings, they
do not affect the overall historic character of the property. Additionally, a
screen of tall plantings shields the solar panels from view from the front of
the building, further limiting their visibility.

Above: Shown from the rear of the property, these

Tall plantings shield solar panels from solar panels serve a secondary function as awnings to
view from the front of the building. shade south-facing windows. Because of their location
at the back of the building immediately adjacent to a
loading dock, the installation of these panels does not
affect the historic character of the property.

Left: The solar panels are not visible from the front of
the building. Additionally, even if the vegetation were
removed, the installation would only be minimally
visible along an alley at the rear of a secondary side
elevation.

Jenny Parker, Technical Preservation Services, National Park Service

These bulletins are issued to explain preservation project decisions made by the U.S. Department of the Interior. The resulting determinations, based on the
Secretary of the Interior’s Standards for Rehabilitation, are not necessarily applicable beyond the unique facts and circumstances of each particular case.
August 2009, ITS Number 52