vvEPA
United States EPA430-R-08-014
Environmental Protection
Agency September 2008
Clean Energy Options for
Addressing High Electric
Demand Days
Report
Prepared for
U.S. Environmental Protection Agency
Climate Protection Partnerships Division
State and Local Programs
http://www.epa.gov/cleanenergy/stateandlocal/
Prepared by:
ICF International
9300 Lee Highway
Fairfax, VA 22031
(703) 934-3000
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Table of Contents
Executive Summary ES-1
1. Introduction 1-1
1.1. Objective 1-1
1.2. Approach 1-1
1.3. Organization of the Report 1-2
2. Clean Energy Policy Best Practices 2-3
2.1. Barriers to Clean Energy Opportunities 2-3
2.2. Clean Energy Policy Best Practices 2-4
3. Energy Efficiency 3-7
3.1. Introduction 3-7
3.2. ENERGY STAR New Homes 3-10
3.3. Home Performance with ENERGY STAR 3-14
3.4. Quality HVAC Installation and Maintenance 3-17
3.5. Appliance Retirement and Recycling 3-21
3.6. PC Power Management 3-23
3.7. Commercial Lighting, Cooling, and Refrigeration 3-26
3.8. Whole Building Energy Performance for the C&l Market 3-30
3.9. Cool Roofs 3-34
4. Demand Response 4-37
4.1. Introduction 4-37
4.2. Incentive Programs 4-38
4.3. Dynamic Pricing 4-42
5. Distributed Generation 5-45
5.1. Introduction 5-45
5.2. Standby Rates 5-46
5.3. Interconnection Requirements 5-50
5.4. Combined Heat and Power 5-53
5.5. Solar Energy 5-56
List of Figures
Figure 3-1. Impact of Quality Installation on AC System Cooling Delivery 3-17
Figure 4-1. Comparison of Dynamic Pricing Structures 4-43
List of Tables
Table 2-1. Barriers to Investment in Clean Energy Opportunities 2-3
Table 2-2. Clean Energy Policy Best Practices 2-4
Table 3-1. Peak Demand Savings Per Unit of Energy Savings for Selected Measures 3-8
Table 3-2. Peak Demand Savings of Residential Measures 3-8
Table 3-3. Peak Demand Savings of Commercial Measures 3-9
Table 3-4. Peak Demand Savings of Industrial Measures 3-9
Table 3-5. Cool Roof Savings 3-35
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Executive Summary
Objective
Nitrogen oxide (NOx) emissions from electrical generating units (EGUs) are a key contributor to
ground-level ozone formation and other regional air quality problems such as acid rain and
smog. Hot summer days are particularly conducive to ground-level ozone formation, and air
conditioning loads on such days are often a major contributor to electricity demand spikes. At
the same time, some EGUs called "peaking units" only operate during periods of peak demand
when the electric grid requires maximum generating capacity, and could be high-emitting
sources. Peaking units might lack NOx controls because they have low emissions on a
seasonal basis, even if hourly emissions are high during periods when they are in use. In
addition, these EGUs are often less economical sources of electric power supply.
As currently designed, emissions standards and air pollution trading programs have limited
success in reducing emissions from EGUs that predominantly operate on high electric demand
days (HEDDs). Existing emissions models and inventories are designed for typical summer
days, not the extreme conditions that occur on HEDDs. Regulatory standards could be
designed for larger EGUs that meet baseload demand, rather than EGUs that are only called on
to meet demand spikes. Using a cap and trade mechanism to promote the cleanup of HEDD
units could require high NOx retirement ratios and might not be an economically viable
approach.
Clean energy policies and initiatives promoting increased energy efficiency, demand response,
and low-emitting distributed generation (DG) technologies offer cost-effective opportunities for
reducing peak electric demand and associated NOx emissions. In addition to air quality
benefits, ancillary benefits of deploying clean energy strategies to reduce peak electric demand
include increased grid reliability while reducing the need to construct new electricity generating
capacity or additional transmission and distribution infrastructure.
Recent EPA analysis in support of an Ozone Transport Commission (OTC) stakeholder process
estimates that implementation of a portfolio of enhanced energy efficiency, DG, and demand
response initiatives could reduce peak day NOx emissions by 4 to 8 percent across the OTC
states in two years of implementation (by 2010), and by 13 to 20 percent within seven years of
implementation (by 2015). Emissions reductions could be even greater with appropriate
provisions to address increased emissions from the use of high-emitting back-up generators
associated with many demand response programs. At the modeled penetration of energy
efficiency, combined heat and power installation, solar photovoltaic installations and demand
response activities, energy efficiency and combined heat and power provided the largest
emissions benefits on HEDDs. Demand response activities did reduce emissions from grid
connected electric generators, but also were estimated to increase emissions at on-site behind-
the-meter diesel generators. The estimated net effect in this modeling exercise was a slight
increase of NOx emissions. The new OTC wide solar PV installations were estimated at 56 to
168 Megawatts (MW) OTC wide; at that penetration rate, they would affect a small decrease in
NOx emissions.
The report summarizes best practices for cross-cutting policies that promote the adoption of
clean energy technologies and provides detailed information on targeted policies and programs
that promote energy efficiency, demand response, and clean DG technologies that could be
employed to deliver significant reductions in peak NOx emissions.
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Executive Summary
Scope
The clean energy opportunities addressed in this report include:
• Policies that that promote broader deployment of clean energy technologies by
addressing existing market and regulatory barriers to clean energy investment, and/or
establishing incentives to promote such investment.
• Energy efficiency initiatives targeting the leading drivers of summer peak electric
demand such as residential air conditioning, commercial heating, ventilation and air
conditioning (HVAC), and commercial lighting.
• Demand response programs that reduce purchased electricity consumption during
periods of peak demand, provided such programs are structured to avoid a net
emissions increase through the use of emissions-intensive sources of backup power
generation.
• Clean DG technologies such as CHP and solar photovoltaic (PV) applications that offset
grid-supplied electricity.
Clean Energy Best Practices
Cross-Cutting Policy Support
Despite the environmental and grid reliability benefits associated with energy efficiency, demand
response and DG technologies, as well as the success of clean energy initiatives at the federal,
state, and local level across the country, the clean energy opportunities discussed in this
analysis remain underutilized as an energy resource and as an emissions reduction strategy.
Cross-cutting state policies that support clean energy development include:
• Establishing quantitative and enforceable goals for energy efficiency, renewable energy,
and/or CHP through energy portfolio standards.
• Leading by example by establishing guidelines for government agencies to follow.
Example guidelines include building energy performance standards, energy efficiency
procurement policies, and renewable energy purchase requirements.
• Offering tax incentives to promote clean energy investment through personal or
corporate income tax credits, tax reductions or exemptions, or tax deductions.
• Creating clean energy funding mechanisms such as public benefits funds that entail a
small per-kWh charge on customer electric bills to fund grants, loans, rebates, technical
assistance, and other strategies for enhancing clean energy investment, where cost
effective.
• Developing regulatory incentive structures to promote utility investment in clean energy
programs, such as mechanisms for program cost recovery, revenue stability, and
performance-based incentives.
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Executive Summary
• Promoting utility rate structures that are more advantageous for the investment and
installation of clean DG (e.g., addressing electric rates for supplying backup power, high
standby connection charges, and exit fees) while ensuring appropriate cost recovery for
utilities.
• Establishing uniform (across multiple utility service territories) rules, processes, and
technical requirements for connecting DG applications to the grid and ensuring that such
requirements are commensurate with the size, nature, and scope of the DG project.
• Facilitating deployment of advanced metering infrastructure to support dynamic pricing
for retail electric customers.
• Incorporating energy efficiency as an important resource into utility resource planning,
along with supply-side resources.
• Including evaluation measurement and verification (EM&V) as an essential part of
energy efficiency program design that documents the results, benefits, and lessons
learned from an energy efficiency program. EM&V can be used for planning future
programs, for determining the value and potential of energy efficiency, and for
retrospectively determining the performance (and payments, incentives, and/or
penalties) of those responsible for implementing efficiency programs.
• Conducting energy efficiency potential studies as an effective tool for building the policy
case for energy efficiency and other clean energy technologies as an alternative to
supply side resources.
It is also important to leverage the relationships that exist between the clean energy
opportunities addressed in this analysis. For example, greater environmental benefits can be
captured through demand response initiatives if grid power is offset with low-emissions onsite
power generating technologies such as CHP and PV, rather than fossil fuel-fired backup
generators. An effective clean energy strategy might employ multiple policy-level best practice
approaches, and require coordinated action on the part of state governors, legislatures, state
energy offices, air and utility regulators, and support from a variety of stakeholders.
Energy Efficiency
Energy efficiency programs can do more than just target and secure energy savings measured
on a kilowatt hour (kWh) basis; they can also achieve peak demand reductions which are
measured on a kilowatt (kW) basis. For energy efficiency programs to address emissions on
HEDDs, it is important to focus programs on loads that are highly coincident with peak demand.
Quantifying the peak demand impacts of energy efficiency programs presents a greater
technical challenge than evaluating energy savings impacts. While electric bills provide energy
use data for all customer classes on a kWh basis, time of use (TOU) meters and demand
meters are not widely distributed across all customer classes. In particular, residential and
small commercial customers typically lack electric demand and TOU meters, making
quantification of peak demand impacts of energy efficiency measures more challenging.
However, there is growing interest in the peak demand impacts associated with energy
efficiency initiatives, in part due to grid congestion and electric supply reliability issues that are
facing some areas of the country.
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Executive Summary
The leading drivers of summer peak electricity demand are residential cooling, commercial
heating, ventilation and air conditioning (HVAC), and commercial lighting. Inefficient home
appliances, commercial refrigeration, and office plug loads represent additional opportunities for
energy efficiency improvement. This report reviews a number of proven energy efficiency
program strategies for addressing these peak demand reduction opportunities, providing
information on program design best practices, strategies for overcoming program barriers, peak
demand impacts, and cost-effectiveness. This report also provides information on successful
program models from around the country.
Table ES-1. Energy Efficiency Program Models Addressed in this Report
Program
Peak Savings
Cost
Residential Sector
ENERGY STAR New Homes: Promotes energy-
efficient new home construction.
Home Performance with ENERGY STAR:
Provides comprehensive energy efficiency
improvement for existing homes.
Quality HVAC Installation & Maintenance:
Promotes proper sizing, installation, and
maintenance practices for residential AC.
Appliance Recycling: Facilitates removal and
recycling of inefficient home appliances.
Commercial Sector
PC Power Management: Promotes activation of
energy-saving features to reduce office plug load.
Commercial Lighting, Cooling, and Refrigeration:
Offers incentives for energy-efficient commercial
equipment.
Whole Building Performance: Provides
comprehensive energy efficiency improvement for
commercial buildings.
Cool Roofs: Promotes roofing materials with high
reflectance and surface emittance.
1 kW per home
$0.01 - $0.08/kWh
Approx 1.6 kW per home $0.05/kWh
0.2-0.7 kW per home $0.03 - 0.04/kWh
0.16-0.4 kW per unit $0.03 - 0.05/kWh
1kW per 150 PCs
0.6-200kWper
participant
16-600 kW per
participant
$0.01 - 0.02/kWh
$0.005 - 0.06/kWh
$0.01 - 0.04/kWh
Demand Response
"Demand response" is a broad term encompassing a range of program types designed to
reduce electricity use during periods of peak electric demand. Demand response initiatives
range from programs that provide customer incentives for voluntary (nonfirm) or mandatory
(firm) load curtailment based on contractual arrangements, to dynamic pricing structures that
charge higher rates during peak periods, employing a market-based approach to achieving peak
demand reduction. Some program administrators are finding that a portfolio of demand
response programs comprised of voluntary and mandatory reduction commitments is the most
cost-effective demand response strategy to accommodate the different technologies and
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Executive Summary
customer preferences in different market sectors. This approach also offers customers
increased flexibility in terms of selecting the demand response option that is best suited to their
risk tolerance.
In order to serve as an effective strategy for reducing HEDD emissions, it is essential that
demand response initiatives be structured to avoid a net emissions increase through the use of
emissions-intensive sources of backup power generation. Combining demand response with
efforts to promote clean DG can be an effective strategy for achieving this objective. Some
program administrators have addressed this issue by including requirements for the types of
load reductions that are eligible for demand response incentives. In addition, policies that
support the deployment of enabling technologies such as advanced metering and
communications infrastructure, sophisticated load control devices, and energy management
devices that provide customers with real time energy usage data help to maximize the impacts
of demand response initiatives.
Distributed Generation
Where energy efficiency and demand response initiatives represent demand-side approaches to
reducing peak electric demand and associated HEDD emissions, CHP and solar PV represent
opportunities for supplanting grid-supplied power with clean, DG alternatives.
CHP refers to the simultaneous production of electricity and heat from a single fuel source.
CHP is not a single technology, but an integrated energy system that can be modified
depending upon the needs of the energy user. CHP technology is best-suited for energy-
intensive facilities with substantial electric and thermal energy loads such as industrial
manufacturing plants and large commercial and institutional facilities. CHP systems require less
fuel to produce a given energy output, and as systems are located onsite where the energy is
used, they eliminate the transmission and distribution losses associated with grid-supplied
electricity.
PV systems generate electricity from solar energy and are another form of clean DG that
displaces grid-supplied power. As the solar resource is greatest on hot summer days when
peak electric demand is typically high, PV systems produce air quality benefits and reduce
strain on the electric transmission and distribution system. Due to the modular configuration of
PV systems, solar electric technology can be utilized in a diverse range of settings, from urban
to rural and from small-scale residential to large-scale commercial applications.
Some of the cross-cutting policy supports for clean energy development discussed above
represent key strategies for reducing barriers to clean DG technologies, namely ensuring
equitable utility rate structures and developing standardized interconnection requirements. DG
applications are typically grid-connected as they supply only a portion of a facility's total energy
requirements. Utility rate structures that disadvantage clean DG applications include high rates
for providing standby service to meet demand when onsite generating capacity is offline. In
addition to requirements prohibiting such practices, a supportive regulatory environment for
clean DG will also establish standardized technical and procedural requirements for connecting
a DG application to the grid, ensuring that requirements are commensurate with the size of the
DG application. Other strategies that have been successful in promoting clean DG include
incentive programs and DG procurement processes.
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1. Introduction
1.1. Objective
Periods of peak electricity demand on hot summer days correlate closely with high levels of
NOx emissions from electrical generating units (EGUs), and with meteorological conditions that
contribute to ground-level ozone formation. As currently designed, emissions standards and air
pollution trading programs have limited success in reducing emissions from EGUs that
predominantly operate on high electric demand days (HEDDs). Clean energy opportunities
such as enhanced energy efficiency, demand response initiatives, and clean forms of distributed
generation (DG) such as combined heat and power (CHP) and solar energy can be cost-
effective strategies for reducing peak electric demand, achieving air quality benefits, and
contributing to electric supply reliability.
This report summarizes best practices for clean energy policies and initiatives that address
summer peak electricity demand. Clean energy strategies addressed in this report include:
• Policies that address existing market and regulatory barriers to clean energy investment
and/or establish incentives to promote clean energy investment.
• Energy efficiency initiatives targeting the leading drivers of summer peak electric
demand such as residential air conditioning, commercial heating, ventilation and air
conditioning (HVAC), and commercial lighting.
• Demand response programs that reduce purchased electricity consumption during
periods of peak demand without increasing the use of emissions-intensive backup
generation.
• "Clean" DG technologies such as CHP and solar photovoltaic (PV) that offset grid-
supplied electricity.
The U.S. Environmental Protection Agency (EPA) has developed this analysis to support states
and air quality planning agencies in their efforts to evaluate clean energy policy and program
opportunities for addressing HEDD emissions.
1.2. Approach
The clean energy best practices discussed in this report were initially compiled by EPA to
support the Ozone Transport Commission's (OTC) HEDD Initiative. In 2006, a group of OTC
states launched a stakeholder process to evaluate opportunities for reducing HEDD emissions
through a variety of approaches, including performance standards and emissions caps for
HEDD units, state/generator HEDD partnership agreements, adjustment of NOx retirement
ratios to provide for HEDD reductions, energy efficiency programs, demand response programs,
and clean DG technologies. Stakeholders included representatives from regional transmission
organizations (RTOs), public utility commissions (PUCs), electric generating companies, and
EPA.
In March 2007, several OTC states signed a Memorandum of Understanding (MOU) to address
HEDD emissions.1 Beginning with the 2009 ozone season, six states are committed to pursue
reductions of NOx emissions associated with HEDDs during the ozone season, with reduction
targets ranging from 20-32 percent. These OTC states are in discussions with individual EGU
companies and stakeholders regarding tailored strategies for achieving these emissions
reduction targets. Strategies for HEDD emissions reductions could include, but are not limited
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Introduction
to, equipment replacement, fuel switching, and control technologies. Further reductions can be
achieved through clean energy initiatives that reduce peak electric demand.
EPA support for the HEDD Initiative included a modeling exercise to estimate NOx emission
reductions that could be achieved through a portfolio of enhanced energy efficiency, demand
response, CHP, and solar energy initiatives. EPA also developed a set of clean energy policy
and program best practices to support the attainment of HEDD emissions reductions goals.
This document updates the initial clean energy best practice report as a more general guide to
other states and regions interested in addressing HEDD emissions.
07C High Electric Demand Day Initiative: NOx Emissions Reduction Potential
• A 2006 EPA analysis estimated that a implementing a portfolio of enhanced
energy efficiency, CHP, solar energy, and demand response initiatives could
reduce peak day NOx emissions by 4 to 8 percent across the OTC states in
two years (by 2010), and by 13 to 20 percent by 2015.
• Emissions reductions could be even greater with appropriate provisions to
address increased emissions from the use of high-emitting back-up generators
associated with many demand response programs.
1.3. Organization of the Report
The major sections of this report are organized as follows:
• Chapter 2, Clean Energy Policy Best Practices, discusses cross-cutting barriers to clean
energy opportunities for addressing HEDD emissions and policy measures that have
been successfully deployed to address those barriers.
• Chapter 3, Energy Efficiency, discusses successful program models targeting peak-
coincident electric loads, program design and implementation, challenges, and examples
of successful programs.
• Chapter 4, Demand Response, discusses programs that employ dynamic pricing to
reduce electric demand during peak periods, or offer customer incentives for shifting or
reducing electric use during peak periods. This chapter includes a discussion of
strategies for ensuring that demand response programs do not contribute to a net
increase in emissions due to the use of emissions-intensive forms of backup power
generation and a discussion of supporting technologies such as advanced metering
infrastructure and devices that automate demand response.
• Chapter 5, Distributed Generation, discusses initiatives that promote clean DG
applications such as CHP and solar energy by reducing barriers to investment and
enabling clean DG technologies to compete on a level playing field with traditional
supply-side resources.
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2. Clean Energy Policy Best Practices
2.1. Barriers to Clean Energy Opportunities
Despite the benefits of clean energy and the success of programs in many states across the
country, clean energy remains underutilized as an energy resource and as an emissions
reduction strategy. Promoting the portfolio of clean energy opportunities discussed in this
report—enhanced energy efficiency, demand
response, and clean DG—requires a
combination of policy refinements and/or
changes, including efforts to address existing
market and regulatory barriers and to
establish appropriate financing mechanisms.
These efforts will likely require action on the
part of state governors, legislatures, energy
offices and/or utility regulatory agencies, in
addition to efforts by air regulatory agencies
and input from a variety of stakeholders.
Highlights: Clean Energy Policy Best Practices
Cross-cutting policy best practices include:
• Promoting coordinated planning between air
regulators and energy regulators.
• Establishing clean energy goals.
• Removing regulatory barriers to clean energy
investment.
• Creating funding mechanisms to support clean
energy opportunities.
The following table lists common cross-cutting barriers to investment in clean energy opportunities.
A more detailed discussion of barriers specific to the clean energy opportunities is addressed in the
relevant chapters.
Table 2-1. Barriers to Investment in Clean Energy Opportunities
Type of Barrier
Description
Market barriers
Customer barriers
Public policy barriers
Utility, state, and
regional planning
barriers
Program barriers
Includes fundamental market characteristics that inhibit investment in clean energy opportunities.
Common examples include the split incentive barrier, where the economic benefits of
increased energy efficiency do not accrue to the decision-maker (e.g., the home builder or
commercial developer who is not responsible for paying the ongoing energy bill), and the
transaction cost barrier, where the costs associated with making the investment (acquiring
information, evaluating risks, etc.) inhibit investment. Transaction cost barriers chronically affect
individual and small business decision-making regarding investment in clean energy
opportunities.
Includes lack of information about clean energy opportunities, lack of awareness of how existing
clean energy programs make investments easier, lack of time and attention to evaluating and
implementing clean energy opportunities, and lack of funding to invest in clean energy
opportunities.
Includes existing policy and regulatory conditions that discourage clean energy investment by
utilities, retail electric service providers, power producers, and transmission and distribution
companies. Historically these organizations have been rewarded more for building infrastructure
(e.g., power plants, transmission lines, pipelines) and increasing energy sales than for helping
their customers use energy wisely, even when the clean energy opportunities might cost less
than building infrastructure.
Includes energy supply planning structures/processes which do not allow clean energy
opportunities to compete equitably with traditional supply-side resources.
Includes sub-optimal clean energy program design and implementation due to lack of knowledge
about the most effective and cost-effective means of promoting clean energy opportunities in the
target market, how best to address common market barriers, and available technologies.
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Clean Energy Policy Best Practices
2.2. Clean Energy Policy Best Practices
A variety of clean energy policy measures can be used to address one or more of these barriers
at the state level and could be adapted for use in other states and regions as shown in the
following table. The table also notes relevant sections of two recent reports (the EPA's Clean
Energy-Environment Guide to Action: Policies, Best Practices and Action Steps for States and
the National Action Plan for Energy Efficiency) that contain more detailed information on these
policies and programs, including descriptions on the roles of key players including state
governors, legislatures, environmental officials, energy offices, utility regulatory agencies, and
stakeholders.
Table 2-2. Clean Energy Policy Best Practices
Policy Best
Practice
Description
Relevant Section in Guide to Action
or National Action Plan
Energy planning Institute energy planning processes that evaluate clean
provisions energy as a resource, set clean energy goals, consider how
best to meet long-term needs, and fully realize the costs and
benefits of different energy resources. Create mechanisms to
promote coordinated planning between air regulators and
energy regulators that serves the dual objectives of ensuring
air quality and grid reliability.
Energy portfolio Establish quantitative and enforceable goals for energy
standards efficiency, renewable energy, and/or CHP through energy
portfolio standards.
Demonstrate Demonstrate clean energy leadership by promoting clean
government energy opportunities for public facilities through mechanisms
leadership such as executive orders that support building energy
performance standards, energy efficiency procurement
policies, and renewable energy purchases.
Tax incentives Provide state tax incentives to promote clean energy
investment such as personal or corporate income tax credits,
tax reductions or exemptions, or tax deductions.
Public benefit Create clean energy funding mechanisms, such as public
funds benefits funds that entail a small per-kWh charge on
customer electric bills to fund grants, loans, rebates, technical
assistance, and other strategies for enhancing clean energy
investment.
Utility incentives Develop appropriate regulatory incentive structures to
for demand-side promote utility investment in clean energy programs, such as
resources mechanisms for program cost recovery, revenue stability, and
performance incentives.
• Guide to Action: 3.2 (State and
Regional Energy Planning) and 6.1
(Portfolio Management Strategies).
• National Action Plan: 3 (Energy
Resource Planning Processes).
• Guide to Action: 4.1 (Energy
Efficiency Portfolio Standards); 5.1
(Renewable Portfolio Standards).
• Guide to Action: 3.1 (Lead by
Example).
• Guide to Action: 3.4 (Funding and
Incentives).
• Guide to Action: 4.2 (Public Benefit
Funds for Energy Efficiency); 5.2
(Public Benefit Funds for State
Clean Energy Supply).
• Guide to Action: 6.2 (Utility
Incentives for Demand-Side
Resources) and 6.3 (Emerging
Approaches: Removing Unintended
Utility Rate Barriers to Distributed
Generation
• National Action Plan: 2 (Utility
Ratemaking & Revenue
Requirements), 5 (Rate Design) and
Appendix A (Additional Guidance on
Removing the Throughput
Incentive).
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Clean Energy Policy Best Practices
Policy Best
Practice
Description
Relevant Section in Guide to Action
or National Action Plan
Standby rates Develop standby rate structures that ensure appropriate cost
recovery for utilities but do not inhibit investment in clean DG
(CHP and renewable energy) by charging excessive rates for
supplying backup power, high standby connection charges,
and exit fees.
Interconnection Establish uniform rules, processes, and technical
standards requirements across utility service territories for connecting
DG applications to the grid, ensuring that such requirements
are commensurate with the size, nature, and scope of the DG
project.
Infrastructure Facilitate deployment of advanced metering infrastructure to
investment support dynamic pricing for retail electric customers.
• Guide to Action: 6.3 (Emerging
Approaches: Removing Unintended
Utility Rate Barriers to Distributed
Generation)
• Guide to Action: 5.4 (Interconnection
Standards)
Resources for Additional Information on Clean Energy Policy Best Practices
• EPA's Clean Energy-Environment Guide to Action: Policies, Best Practices and
Action Steps for States.
o Identifies and describes 16 clean energy policies and strategies that states
have used to meet their clean energy objectives.
o Web site: http://www.epa.gov/cleanenergy/stateandlocal/guidetoaction.htm.
• National Action Plan for Energy Efficiency, facilitated by EPA and DOE.
o A plan developed by more than 50 leading organizations in pursuit of energy
savings and environmental benefits through electric and natural gas energy
efficiency.
o Web site: http://www.epa.gov/cleanenergy/actionplan/eeactionplan.htm.
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3. Energy Efficiency
3.1. Introduction
Energy Efficiency, which refers to using less energy to provide the same or improved level of
service to the energy consumer, can be an effective way to provide peak demand savings in
addition to overall energy savings, depending on the types of equipment and loads that are
targeted. For energy efficiency programs that address emissions on HEDDs, it is important to
focus programs on loads that are coincident with peak demand. There is growing information
on the potential to reduce peak demand through energy efficiency programs. The impacts of
energy efficiency initiatives can be assessed in terms reduced electricity consumption, typically
measured in terms of kilowatt hours (kWh) of electricity saved, or in terms of the reduction in
peak demand for electricity, typically measured in terms of kilowatts (kW) of peak demand
reduction. The primary objective of most energy efficiency programs is to produce energy
savings (kWh) rather than peak demand reduction (kW). Historically there have been limited
resources devoted to assessing the peak demand impacts of energy efficiency programs. While
electric bills provide energy use (kWh) data for all customer classes, time of use (TOU) meters
and demand meters are not widely distributed across all customer classes. In particular,
residential and small commercial customers typically lack electric demand and TOU meters,
making quantification of peak demand impacts of energy efficiency measures more challenging.
Even with advanced metering infrastructure, it may still be difficult to isolate the peak demand
impacts associated with individual energy efficiency measures, and primary data collection
efforts are costly. Typical approaches for assessing peak demand impacts involve applying
load shapes or load factors to energy savings data. In order to meet short-term operating
requirements and in connection with long term electric demand forecasting, utilities have
developed comprehensive load shape data for their customer base. Individual load shapes
have even been developed down to the level of market sub-segments such as single family
homes and small commercial facilities.2
The American Council for an Energy Efficient Economy (ACEEE) recently completed an
assessment of the peak demand impacts of energy efficiency programs nationwide.3 The data
presented in this assessment demonstrate how much the relationship between overall energy
savings (kWh) and peak demand reduction (kW) can vary based on the end use characteristics
of each individual measure. Climate-sensitive measures such as heating and cooling
applications show particular variability. Table 3-1 presents peak demand savings (in watts) per
unit of energy savings (kWh) for a number of common energy efficiency measures that have
substantial effect on peak demand. The ACEEE study also developed a database of program-
reported peak demand impacts at the measure level for a variety of residential, commercial, and
industrial energy efficiency measures. Minimum, maximum, and medium kW impacts for a
variety of measures, as compiled by ACEEE, are reported in tables 3-2 through 3-4 below.3
The tables demonstrate that energy efficiency measures offer the potential for peak demand
reduction across all sectors (residential, commercial, and industrial) with residential and
commercial heating and cooling applications, commercial lighting, HVAC, and refrigeration
representing key areas of peak demand reduction opportunity. The remaining sections in
Chapter 3 discuss a number of energy efficiency program models that have a proven record of
achieving peak demand reduction. Information is provided on the following program areas:
• ENERGY STAR New Homes
The full set of measure-level data compiled by ACEEE is available at: http://www.aceee.org/pubs/uQ73.pdf.
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Energy Efficiency
• Home performance with ENERGY STAR
• Quality HVAC Installation and Maintenance
• Appliance Retirement and Recycling
• PC Power Management
• Commercial Lighting, Cooling, and Refrigeration
• Whole Building Energy Performance for the C&l Market
• Cool Roofs
Table 3-1. Peak Demand Savings Per Unit of Energy Savings for Selected Measures4
Energy Efficiency Measure W/kWh (Median Value)
ENERGY STAR room A/C 1.59
Refrigerator recycling1" 1.54
Energy-efficient central A/C 1.29
Energy-efficient packaged rooftop HVAC (5-12 tons) 0.74
Energy-efficient chiller (150-300 tons centrifugal) 0.59
T-8 fluorescent lamp with electronic ballast 0.31
Premium efficiency motor (25 hp) 0.26
Premium efficiency motor (200 hp) 0.18
ENERGY STAR refrigerator 0.14
Compact fluorescent light bulb 0.10
Table 3-2. Peak Demand Savings of Residential Measures5
Coincident Summer Peak Demand Savings
Energy Efficiency Measure
ENERGY STAR room A/C
Energy-efficient central A/C
ENERGY STAR refrigerator
ENERGY STAR freezer
ENERGY STAR clothes washer
Min (kW)
0.058
0.435
0.006
0.005
0.009
Max (kW)
0.067
0.864
0.011
0.005
0.193
Median (kW)
0.063
0.742
0.009
0.005
0.051
Data Points
3
4
4
1
4
b Ratio of demand reduction to energy savings for refrigerator recycling is derived from data in the Final Report Impact
Evaluation of the Spare Refrigerator Recycling Program, CEC Study #537, completed by Xenergy for Southern California
Edison.
U.S. Environmental Protection Agency 3-8 September 2008
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Energy Efficiency
Coincident Summer Peak Demand Savings
Energy Efficiency Measure
Compact fluorescent light bulb
Fluorescent torchiere
ECM furnace fan
Min (kW)
0.004
0.020
0.147
Max (kW)
0.009
0.028
0.147
Median (kW)
0.006
0.025
0.147
Data Points
4
3
1
Table 3-3. Peak Demand Savings of Commercial Measures
Coincident Summer Peak Demand Savings
Energy Efficiency Measure
Energy-efficient packaged rooftop HVAC (5-12 tons)
Energy-efficient chiller (150-300 tons centrifugal)
Variable speed motor drive
Compact fluorescent light bulb
Premium efficiency motor (5 hp)
Premium efficiency motor (10 hp)
Premium efficiency motor (25 hp)
T-8 fluorescent lamp with electronic ballast
Commercial packaged refrigeration
Commercial vending machine control
High efficiency copier
Min (kW)
0.020 kW/ton
0.067 kW/ton
0.071 kW/hp
0.006
0.056
0.117
0.151
0.006
0.112
0
0.041
Max (kW)
0.232 kW/ton
0.102 kW/ton
0.252 kW/hp
0.039
0.070
0.148
0.191
0.008
0.112
0.114
0.041
Median (kW)
0.083 kW/ton
0.085 kW/ton
0.203 kW/hp
0.026
0.063
0.133
0.171
0.008
0.112
0.057
0.041
Data Points
4
2
3
4
2
2
2
3
1
2
1
Table 3-4. Peak Demand Savings of Industrial Measures7
Coincident Summer Peak Demand Savings
Energy Efficiency Measure
Premium efficiency motor (40-50 hp)
Premium efficiency motor (75 hp)
Premium efficiency motor (150 hp)
Premium efficiency motor (200 hp)
Min (kW)
0.219
0.474
0.575
1.146
Max (kW)
0.471
0.551
0.728
1.450
Median (kW)
0.345
0.513
0.652
1.298
Data Points
2
2
2
2
U.S. Environmental Protection Agency
3-9
September 2008
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Energy Efficiency
3.2. ENERGY STAR New Homes
3.2.1. Overview
Residential energy use accounts for 21 percent ,,.,,.,
of U.S. primary energy consumption.8 New »**"»**
Demand reduction: 1 kW per home.
Technologies: Effective insulation, high-
performance windows, tight construction and
ducts, efficient heating and cooling equipment,
efficient lighting, and appliances.
Cost effectiveness: $0.01-0.08/kWh.
ENERGY STAR information at:
www.energystar.gov/homes.
home construction is an important segment of
the housing market in which energy efficient
design and construction techniques can lock in
energy savings for decades. Energy-efficient
new home construction offers a cost-effective
approach to reducing peak demand and
improving comfort. Each ENERGY STAR
qualified home is at least 15 percent more
efficient than homes built to the 2004
International Residential Code, and depending
on the geographic area covered by the program, can be as much as 20-30 percent more
efficient than prevailing local code.
EPA works with builders and energy efficiency program sponsors nationwide to adopt energy
efficient technologies and "on-the-shelf" building practices that enable their homes to qualify for
ENERGY STAR. EPA also works with the U.S. Department of Energy (DOE) Building America
Research Program to promote new techniques and products to improve the overall energy
efficiency of new homes to reach the ENERGY STAR specification or higher.
Currently, over 5,000 builder partners voluntarily label their homes, including over half of the
nation's top 100 largest builders. In 2005, over 160,000 homes earned the ENERGY STAR
label or approximately 10 percent of all new home construction nationwide. Cumulatively, there
are over 840,000 labeled homes and a growing number of regional and local markets with 20 to
50 percent or more market penetration. Together, these homes are saving American
homeowners nearly a half-billion dollars on their utility bills while reducing peak demand by 600
MW.
3.2.2. Best Practices
Technical requirements for achieving the ENERGY STAR label are developed by EPA based on
extensive interaction with the nation's home building industry, detailed technical analyses, and
public review process with the home building industry stakeholders and Home Energy Rating
System (HERS) industry. A home can qualify using a performance path based on a maximum
HERS Index Score, or a prescriptive path using an EPA-developed Builder Option Package
(BOP). EPA has developed separate program requirements for manufactured homes built to
U.S. Department of Housing and Urban Development (HUD) requirements. This includes a
unique verification protocol incorporating quality control processes already included in HUD
code homes manufacturing plants.
In some areas, a utility, state or local government agency, or energy efficiency program
administrator serves as the program sponsor, providing education and training, incentives, and
marketing assistance to builders that construct homes meeting the ENERGY STAR
specification. Though ENERGY STAR homes are being built in areas without an active
program sponsor, active program sponsors can play an essential role in increasing market
penetration of homes that meet the standard. ENERGY STAR homes programs are designed
U.S. Environmental Protection Agency 3-10 September 2008
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Energy Efficiency
to increase the effectiveness of key market actors including builders, HERS providers and
raters, and realtors, as well as to stimulate consumer demand through marketing efforts.
Program design starts with an assessment of the local/regional market for new homes including
the following market factors: predominant type of builder, level of housing dispersion, rigor of
prevailing energy code and enforcement, availability of energy efficient technologies and
construction practices, health and durability issues in new home construction, and relevant
marketing messages for the target market.
EPA recommends a number of critical program elements. First, it is essential to ensure the
presence of a HERS verification infrastructure and to develop and nurture it where not fully
mature. Second, providing builder sales training is critical. Lastly, investments in effective
marketing stimulate market demand and are crucial for success. In addition to building
consumer awareness, program support for builder sales and marketing efforts help secure
builder confidence in the program.
3.2.3. Barriers
Barriers to the adoption of energy efficiency technologies in the home building industry include:
industry resistance to change and concerns with risk; first cost decision making which ignores
utility cost savings and improved comfort, durability and indoor air quality; lack of skills selling
energy efficient homes; lack of consumer awareness; and lack of technical infrastructure for
construction and verification. An effective ENERGY STAR homes program addresses these
key market barriers through marketing, outreach, and training efforts, and presents a strong
business case for builders.
3.2.4. Peak Demand Impacts
EPA has developed national peak demand reduction and energy savings estimates for
ENERGY STAR qualified homes based on current specifications. EPA estimates peak demand
reduction of 1kW per home.c EPA estimates annual energy savings of approximately 3,500
kWh for an all-electric home and approximately 2,030 kWh and 131 therms for a home with
electric cooling and gas heating.
Programs employ a number of key metrics to track and ensure savings and peak load reduction
targets are being met. HERS raters report the number of labeled homes for a given geographic
area, and this total can be multiplied by the above savings numbers to provide a general
estimate total program impacts. More detailed assessments of peak demand impacts involve
field evaluations of the HERS verification process, assessments of actual utility bills for labeled
and control homes, and measurements of peak energy use for labeled and control homes.
When planning measurement and evaluation activities, the HERS certification process includes
oversight by the Residential Energy Services Network (RESNET). RESNET can be contacted
to explore how to leverage their quality assurance efforts.
3.2.5. Cost Effectiveness
Consistently strong cost-effectiveness performance has been documented by many of the more
than 50 regional sponsors implementing ENERGY STAR homes. Some program administrators
This is a national number used by EPA for planning purposes; more climate-specific energy savings per home can be readily
generated through a number of software programs.
U.S. Environmental Protection Agency 3-11 September 2008
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Energy Efficiency
are implementing ENERGY STAR homes programs at approximately $0.06/kWh.de However,
the cost effectiveness is highly dependent on climate, with greater cost effectiveness in regions
having higher cooling loads/ Other variables that affect cost effectiveness include incentive
levels, program maturity, market maturity, geographic concentration of builders, and access to
an established home energy rating infrastructure. Additional cost savings can come into play
where there are both electricity and heating fuel savings. Non-energy benefits such as
improved comfort, indoor air quality, and durability also add value to homebuyers.
3.2.6. Program Examples
The following programs demonstrate how effective regional solutions for implementing
ENERGY STAR homes programs have helped transform residential construction markets.
• New York State Energy Research and Development Authority (NYSERDA), New
York: Transforming the home building industry in upstate New York presented
substantial challenges for NYSERDA. The industry was dominated by widely dispersed,
hard to reach small and mid-size regional builders. NYSERDA responded by first
developing a strong HERS industry across the region. NYSERDA then provided
extensive training to home builders, offered substantial rebates, and implemented an
effective regional marketing campaign conveying the benefits of energy efficiency.
Since the inception of the ENERGY STAR homes program five years ago, market
penetration is over 10 percent and ENERGY STAR for homes is positioned for strong
continued growth. Program web site:
http://www.getenergvsmart.org/SingleFamilvHomes/NewConstruction/HomeOwner.aspx.
• CenterPoint Energy and Oncor/TXU, Texas: Joining forces in Houston and Dallas,
these two utilities realized that their markets were dominated by large production
builders. It was critical in their markets to expand the HERS verification infrastructure
and effectively market the benefits of energy efficiency to consumers. Both utilities
implemented ENERGY STAR homes programs with extensive efforts to recruit HERS
providers in their respective markets, a minimal rebate to builders, and a strong
advertising campaign educating local home buyers. As a result, during a five year
period, Houston and Dallas have achieved a respective 35 and 45 percent market
penetration for ENERGY STAR qualified homes. Program web sites:
http://centerpointefficiencv.eom/energvstar/h verify.htm and
http://www.oncorgroup.com/electricity/teem/services/starhomes/default.aspx.
• Las Vegas ENERGY STAR Partners, Nevada: A strong group of builders, HERS raters
and local home building marketing professionals formed an alliance to promote
ENERGY STAR qualified homes. This group effectively implemented outreach
campaigns advertising the benefits of ENERGY STAR to homebuyers, and worked
together to develop and disseminate on-site marketing materials. They also provided
technical and marketing training, and promoted the results of their efforts at local
d Levelized cost of $0.06/kWh sourced from http://www.energystar.gov/ia/partners/downloads/meetings/NewHomesHPwES.pdf
e Program data from NYSERDA in 2004 shows levelized CCE of $0.04/kWh, and Long Island Power Authority data from 2003
shows levelized CCE of $0.08/kWh.
f Program data from TX, CenterPoint Energy, Oncor/TXU, and Entergy Gulf States show levelized CCE in the range of $0.01 to
$0.02/kWh (calculated levelized cost of conserved energy using first year savings (kWh), a discount rate of 6%, and a lifetime
of 16 years).
U.S. Environmental Protection Agency 3-12 September 2008
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Energy Efficiency
industry conferences. As a result, after five years, nearly 60 percent of all homes in Las
Vegas are labeled ENERGY STAR without any monetary incentives, and home buyer
ENERGY STAR awareness exceeds 95 percent. Other programs have succeeded
without rebates in markets such as Phoenix (over 30 percent market penetration) and
Indianapolis (nearly 20 percent market penetration) where a strong champion, individual
or group, effectively promoted ENERGY STAR qualified homes.
U.S. Environmental Protection Agency 3-13 September 2008
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Energy Efficiency
3.3. Home Performance with ENERGY STAR
3.3.1. Overview
For the existing residential market, Home ,,.,,., ,, „ _,
Performance with ENERGY STAR represents a H'9h"9hts: Home Performanc* Wlth ENERGY STAR
Demand reduction: Approx. 1.6 kW per home.
Technologies: Central HVAC equipment
replacement/tune-ups, insulation, air sealing, and
duct sealing, high-performance windows, efficient
lighting, and appliance recycling/replacement.
Cost effectiveness: $0.05/kWh.
ENERGY STAR information at:
www.enerqvstar.gov/homeperformance.
proven strategy for promoting comprehensive
home energy efficiency improvements that
capture significant energy savings potential.
The program, which generates savings through
improving heating and cooling systems,
windows, insulation, and reducing air leakage, is
especially timely as increasing product
standards mean less savings potential from
program strategies that focus on single end
uses such as lighting or HVAC. The greatest
peak demand impacts are associated with improving home heating and cooling efficiency,
particularly in regions with substantial cooling loads.
After more than 20 years of energy efficiency programs in existence in some parts of the
country, there is still enormous potential to reduce energy consumption and peak demand,
especially from older homes. Typical home performance improvements will deliver electricity
savings as well as heating fuel savings. Non-energy benefits like comfort also help as they
convince homeowners to make improvements and make a lasting, positive impression.
3.3.2. Best Practices
A whole-house energy audit is a good first step toward energy efficiency improvement, but
recommendations are seldom implemented if the homeowner does not know who to trust to
complete the work or is unable to easily finance improvements. Through Home Performance
with ENERGY STAR, the contractor who completes the home assessment is also prepared to
complete the needed renovations or work closely with participating contractors who can do so.
Programs that offer homeowners a quick and easy way to finance improvements see even
better results.
A local or regional program administrator is crucial to the implementation and operation of Home
Performance with ENERGY STAR. Organizations such as a utility, state energy agency or non-
profit energy efficiency organization are typical program administrators who understand local
market conditions and can provide third-party oversight of home improvement contractors.
Measurement and verification of results is another important element of a successful program.
Program administrators typically track the number of contractors participating, projects
completed, and average energy saved per project based on information submitted by the
contractor as a condition of program participation, rebates processed, and/or financing
information. Making contractor training and incentive offerings contingent upon the submission
of documentation is an early program design consideration.
ENERGY STAR provides program sponsors with assistance in program planning, promotion
and contractor participation. To do this, EPA and DOE have established a national network of
experienced program implementers, building scientists, marketing and ad firms, and contractors
that can serve to advise and assist in program start-up and delivery.
U.S. Environmental Protection Agency 3-14 September 2008
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Energy Efficiency
3.3.3. Barriers
Program implementers need to consider local market conditions in their planning process, as
there are several common barriers to address in program design and implementation. Common
barriers and strategies for overcoming them include:
• Contractor participation: In many markets there is a limited supply of qualified
contractors with the skills to diagnose and market whole-house energy efficiency
improvements. A key strategy to overcome this barrier is to help develop a local network
of qualified professionals. Offering technical training to participating home improvement
trade contractors is one place to start. Many program sponsors offer sales and business
process training to help contractors succeed in selling and delivering home performance
services.
• Financing home improvements: The up-front cost to the homeowner of whole-house
energy efficiency improvements is another common barrier. Several programs offer
financing for home improvements. Cash rebates can also help generate consumer
interest in the program and offset some costs, especially when the rebates are
contingent on the purchase of a comprehensive package of improvements from
participating contractors.
• Consumer awareness: Many homeowners are not aware that a whole-house
assessment can uncover their home's performance problems and identify improvements
that, when made together, can greatly improve their home's energy efficiency and
comfort. Program administrators can use a variety of marketing and media activities to
overcome this barrier.
• Quality assurance: Quality assurance reassures homeowners that participating
contractors will be held accountable for the work they perform. Following a quality
assurance plan will help streamline delivery and avoid problems associated with
contractor reporting. This plan will determine how and what information contractors will
submit and how it will be reviewed, and these data will become the basis for the
evaluation of program impacts (demand reduction, etc.).
3.3.4. Peak Demand Impacts
EPA estimates a summer peak electricity demand saving of 1.6 kW per home, with the greatest
impacts experienced in areas with substantial cooling loads. Existing home performance
programs have achieved even better results. Austin Energy's 2005 results estimated a deemed
savings per participant of more than 2,500 kWh of electricity and 2 kW in peak demand. As
home improvements are verified through a quality assurance process, there is relatively little
risk that program investments will not produce savings.
3.3.5. Cost-Effectiveness
Building a network of qualified professionals to deliver whole-house services requires
substantial resources, particularly during the first year of implementation. This is one reason
many program administrators choose to start with a pilot program in a target market. A pilot
program allows for flexibility to work out the details of efficient program design and delivery.
Once the infrastructure is established in the pilot market, the investment to maintain and expand
the program decreases and the cumulative savings increase. For mature programs, cost
effectiveness estimates show that Home Performance with ENERGY STAR has a levelized cost
U.S. Environmental Protection Agency 3-15 September 2008
-------
Energy Efficiency
of conserved energy of about 0.05 $/kWh. For programs with integrated gas and electric
savings, the cost effectiveness will be even higher.
3.3.6. Program Examples
Over the past five years, EPA and DOE have worked with states, utilities, and others to develop
and pilot Home Performance with ENERGY STAR in a dozen markets with good results.
Program pioneers, like those noted below, have collectively improved the efficiency of nearly
36,000 existing homes and saved their customers an estimated $400 per year in energy costs.
• NYSERDA, New York: From 2001 through middle of 2007, over 150 contractors
participating in NYSERDA's Home Performance with ENERGY STAR program helped
New Yorkers invest over $110 million to improve the energy efficiency of more than
15,000 homes, saving over 16,000 MWh of electricity and over 600,000 MMBtu of fossil
fuels.9 As of 2005, the net verified summer peak demand reductions attributable to the
program were 1.7 MW, based on installations at over 9,500 homes.10 Program web site:
http://www.getenergvsmart.org/WhereYouLive/HomePerformance/overview.asp.
• Focus on Energy, Wisconsin: The statewide energy efficiency program in Wisconsin,
Focus on Energy, has run a successful Home Performance with ENERGY STAR
program since 2003, and also provides subsidized home performance services to
income-eligible customers. Over 5,000 homes have received home performance
assessments since 2003, with nearly 40 percent of homes installing at least one major
building performance-related measure within the year that the home assessment was
conducted. From July 2006 to June 2007, over 2,000 homes received an assessment
and over 700 homes implemented improvements, achieving a net verified peak demand
reduction of 222 kW.11 During the same year, the program produced electric savings of
over 325,000 kWh and natural gas savings of almost 300,000 therms. Program web
site: http://www.focusonenergy.com/page.jsp?pageld=34.
• Austin Energy, Texas: In 2005, Austin Energy had over 70 contractors participating in
its Home Performance with ENERGY STAR program, completing 1,400 projects with a
peak demand savings of over 3,000 kW. Program Web site:
http://www.austinenergv.com/Energv%20Efficiency/Programs/Rebates/Residential/Hom
e%20Performance%20with%20Energy%20Star/index.htm.
U.S. Environmental Protection Agency 3-16 September 2008
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Energy Efficiency
3.4. Quality HVAC Installation and Maintenance
3.4.1. Overview
Air conditioning accounts for about 14 percent
of residential electricity use in the United
States.12 More than 53 percent of existing
homes have central air conditioning, with this
percentage on the rise as four out of five new
homes are constructed with central AC. Central
air conditioners and heat pumps rank as the
third largest end use of energy in the home,
behind space and water heating.13
Highlights: Residential HVAC
Quality Installation & Maintenance
Demand reduction: 0.2 - 0.7 kWper home.
Technologies: Proper sizing and installation of
residential HVAC systems; corrections to
refrigerant charge and airflow; duct sealing.
Cost effectiveness: $0.03 - 0.04/kWh.
There are substantial energy efficiency and peak demand reduction opportunities associated
both with the sizing and installation of new central AC systems, as well as with ensuring proper
maintenance of existing systems. Common problems that reduce AC efficiency include
improper sizing, improper refrigerant charge, improper airflow over the indoor coil, and air duct
leakage. When all of these issues occur, the efficiency of AC equipment could be reduced by
30 percent.
Figure 3-1. Impact of Quality Installation on AC System Cooling Delivery
Quality Installation Delivers 100% Cooling;
Problem Installations Don't
Installed to
ENERGY STAR
Guidelines
Low Airflow Low Airflow Low Airflow
Improper Improper
Charge Charge
Duct
Leakage
Approximately 5 percent of air conditioners are replaced each year, and getting the installation
right represents a good opportunity to reduce electric demand. For existing equipment, some
estimates showing that as many as 78 percent of central AC units are improperly charged and
up to 70 percent have improper airflow. Adopting a regular diagnostic and maintenance
program can improve the efficiency and performance of existing equipment.
U.S. Environmental Protection Agency
3-17
September 2008
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Energy Efficiency
3.4.2. Best Practices
Many programs have promoted high efficiency AC equipment to reduce peak demand in the
past. This approach continues, but is less effective since the minimum energy efficiency
standard for residential central air conditioners increased to a Seasonal Energy Efficiency Ratio
(SEER) of 13. Best practice for energy efficiency programs is rapidly evolving toward a focus
on proper sizing, installation, charge and airflow for both new and existing systems. It is
expected that this program approach will become increasingly common as standards and
protocols are established.g
Successful programs typically adopt best practice standards for installation and train contractors
to meet them. A trade association, such as the Air Conditioning Contractors of America
(ACCA), can help to identify contractors interested in participating. The best time to engage
contractors is during the fall or spring when business is slower and they are more receptive to
new business opportunities. Training is essential to explain program incentives, standards, and
expectations.
Contractors are typically required to document the installation or tune-up on forms that must be
submitted to the program before an incentive is issued to the consumer or contractor. Some
form of verification procedure or quality assurance inspection is used to ensure compliance with
program standards. Some programs contract with a third party verification service that works
with contractors and remotely verifies installation criteria such as air flow and refrigerant charge.
The most successful programs to date are operated by utilities or state energy agencies. For
example, utilities in NJ, MA, NY and Rl have offered programs with incentives for high efficiency
residential central air conditioners or heat pumps and for quality installation.
In addition to a quality installation there are other home improvements that can reduce cooling
demand. Improvements to a home's thermal envelope, such as air sealing, adding insulation,
and installing ENERGY STAR qualified windows will also reduce the amount of time the air
conditioner runs to keep the home comfortable. ENERGY STAR'S DIY Guide to Home Sealing
is an excellent resource to encourage homeowners to make improvements to their home's
thermal envelope.
EPA is developing the ENERGY STAR HVAC Quality Installation Program that will build on the
efforts of the Air Conditioning Contractors of America and other industry stakeholders to develop
a quality installation specification. EPA is dedicating resources to develop the right tools and
consumer messages to grow the program. EPA will work closely with program administrators
and develop customized materials for the promotion of proper installation of HVAC equipment.
3.4.3. Barriers
Implementing a quality installation and maintenance program requires a commitment to work
with HVAC trade contractors and play a role in technician training and mentoring. To maintain
the credibility of the program, it is essential to verify that contractors are meeting program
standards. When standards are not enforced, the program does not achieve the expected
savings, and the business of contractors following program standards is damaged. Some
programs use an independent organization, called a verification service provider, to verify that
9 Though this section focuses on the residential market, AC installation and tune-up programs are also a successful strategy for
achieving peak demand savings in the commercial market.
U.S. Environmental Protection Agency 3-18 September 2008
-------
Energy Efficiency
air flow and refrigerant charge are correct. Programs have also used on-site inspections to
verify that program standards are met.
3.4.4. Peak Demand Impacts
Program-reported demand reductions range from 0.2 kW per home to around 1 kW per home,
with the greatest impacts experienced in areas with substantial cooling loads.h
Programs employ a number of key metrics to track key savings and ensure that peak load
reduction targets are being met. Use of a third party verification service provides a built-in
system for verifying the activities of participating contractors, although program implementers
have found that random spot checks of contractors are necessary to ensure accurate reporting.
3.4.5. Cost-Effectiveness
Central AC installation and maintenance programs report a levelized cost of conserved energy
(CCE) between $0.03 and $0.04/kWh.' Programs are most cost-effective in warm climates
where high equipment usage produces larger energy savings and where there is a high market
saturation of central AC systems.
3.4.6. Program Examples
• Long Island Power Authority (LIRA), New York: LI PA has offered financial incentives
for the installation of high efficiency HVAC equipment with documentation of proper
installation for several years. In 2006, third-party verification of charge and air flow was
instituted into the program. Similar programs in Massachusetts and Rhode Island are
also using third-party verification of air flow and refrigerant charge. LI PA estimates a
per-unit savings of 1,364 kWh/year and peak demand savings of 1.75 kWwhen an old
10.2 SEER unit is replaced with a new 15 SEER unit that is installed correctly. Program
Web site: http://www.lipower.org/cei/coolhomes.html.
• New Jersey Clean Energy Program, New Jersey: The COOLAdvantage Program,
funded by a systems benefit charge, offers financial incentives for proper installation of
high efficiency HVAC equipment. In 2005, over 600 HVAC technicians received sales
and technical training, and over 17,000 central air conditioning units or heat pumps were
installed achieving an estimated savings of 15,012 MWh of electricity and 12.7 MWof
demand reduction.14 Program Web site:
http://www.nicleanenergv.com/residential/programs/cooladvantage/cooladvantage-
program.
• Oncor, Texas: Through the Air Conditioning Installer Program, Oncor provides
technician training on proper installation practices for air conditioning and duct systems.
An independent verification confirms that the installations meet program specifications,
and the homeowner receives a "High Performance Installation" certificate. Small
installer incentives are offered to offset additional labor and materials costs associated
with a quality installation project. In 2003, the program achieved a peak demand
reduction of nearly 1,800 kW and electricity savings of over 2,600 MWh. In 2004, the
h Based on reported results from Great River Energy, the New Jersey Clean Energy Program, and Proctor Engineering's
CheckMe! program.
' EPA estimates levelized CCE based on data from PG&E.
U.S. Environmental Protection Agency 3-19 September 2008
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Energy Efficiency
program achieved a peak demand reduction of over 9,000 kW and electricity savings of
over 12,000 MWh, while distributing fewer incentive dollars to participating contractors.
An evaluation of the 2003-2004 programs concluded that these results indicate the
program is achieving its market transformation objectives.15 Program Web site:
http://www.oncor.com/electricity/teem/consumer/ac installer/default.aspx.
• Northeast Energy Efficiency Partnership (NEEP): NEEP facilitates information
exchange to increase sales of high efficiency AC systems using quality installation
practices. NEEP is working to change the northeast residential HVAC market to one in
which most consumers choose efficient equipment and systems, and most service
providers use quality installation practices when installing and servicing HVAC
equipment and systems. In 2006 NEEP completed a research project on behalf of the
NJ Board of Public Utilities and the New York State Energy Research and Development
Authority (NYSERDA) with State Technologies Advancement Collaborative (STAC)
funding from DOE to inform the development of common regional quality installation
protocols. As an outcome of this effort, NEEP published a regional market
transformation strategy residential HVAC. Program Web site:
http://www.neep.org/initiatives/Res HVAC.html.
U.S. Environmental Protection Agency 3-20 September 2008
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Energy Efficiency
3.5. Appliance Retirement and Recycling
3.5.1. Overview
For new appliances such as refrigerators, freezers I ,,.,,., ... „
and room air conditioners, tightening efficiency H'9h"9hts: Appliance Recyc""9
Demand reduction: 0.16 - 0.4 kW per unit.
Technologies: Retirement and recycling of
inefficient working refrigerators, freezers, and
room AC.
Cost effectiveness: $0.03-0.05/kWh.
standards means the incremental peak demand
savings between premium efficiency equipment
and standard equipment is smaller, but there is
still a large amount of inefficient old equipment on
the grid. For example, of the existing stock of
refrigerators in U.S. homes, approximately 25
percent (31 million) were manufactured before
minimum efficiency standards took effect in 1993.16 By implementing an appliance retirement
and recycling program, energy efficiency program sponsors are able to reduce energy
consumption and peak demand by removing high-energy consuming refrigerators, freezers, and
room air-conditioners from the grid and by ensuring that they are not put back on the secondary
market. As an additional benefit, programs are also able to reduce emissions of ozone-
depleting substances (ODS) and greenhouse gases by ensuring that the refrigerants and foams
contained in appliances are properly removed and recycled/destroyed.
3.5.2. Best Practices
Promoting the retirement and recycling of old, inefficient refrigerators or freezers through a turn-
in incentive program is a straightforward model for achieving cost-effective energy savings.
Programs typically offer a turn-in incentive and cost-free pickup of the functioning older
appliance. The average incentive is around $35 per appliance, though some programs have
offered an incentive as high as $50.
Appliance recycling programs are a common program model for utilities, with many utilities
simplifying program administration by contracting with a national or regional appliance recycling
company to implement the program. These companies provide turnkey implementation
services including eligibility verification, appointment scheduling, appliance pickup, recycling
and disposal, and incentive processing. Some programs stipulate disposal requirement,
specifying that recycling contractors incinerate foam insulation to prevent the release of
chlorofluorocarbons (CFCs).
To ensure a high net-to-gross ratio (the ratio that adjusts gross energy savings to determine the
net energy savings for which the recycling program should actually be credited) programs often
specify key eligibility criteria such as appliance size, age (for example, some programs specify
that refrigerators must be models produced before 1993 efficiency standards took effect), and
requirements that units are functioning at the time of pick up. Consumers should be informed
that they will be charged a fee to recycle equipment that is not functioning.
Most programs include a strong marketing and consumer education component emphasizing
the cost of keeping a second refrigerator or freezer in the basement or garage, as well as
education on the savings associated with replacing primary refrigerators that were
manufactured before 1993.
In addition, some programs work with major appliance retailers to offer an incentive for
retirement and recycling of refrigerators when new appliances are delivered to ensure that older
refrigerators do not become second refrigerators or are not sold through resale markets.
U.S. Environmental Protection Agency 3-21 September 2008
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Energy Efficiency
3.5.3. Barriers
In general, appliance recycling programs show declining cost effectiveness and peak demand
impacts with time as the market is depleted. A recent review of refrigerator recycling programs
suggests that in the early years of a program, most participants will retire (and not replace)
secondary models, while in later years of implementation a higher percentage of participants will
replace primary equipment.17 Thus, education and incentives to promote the purchase of ENERGY
STAR qualifying new equipment might be beneficial for long-standing programs—new ENERGY
STAR qualifying refrigerators use less energy than a 75-watt light bulb.
3.5.4. Peak Demand Impacts
The energy benefits attributed to the program are the product of the energy consumption of
collected appliances, the remaining life of those appliances, and the net-to-gross ratio. Typical
peak demand impacts per unit for refrigerator retirement programs range between 0.16 kWand
0.28 kW.j Programs that included room air-conditioners in their evaluation estimated summer
peak demand savings between 0.34 and 0.41 kW.18 While air-conditioners consume less energy
annually, they achieve the greatest savings in summer peak demand when compared with
refrigerators and freezers.
3.5.5. Cost Effectiveness
According to the Appliance Recycling Centers of America Inc. (ARCA), the cost of an appliance
recycling program is roughly the same regardless of its location throughout the country—about
$90 to $110 per unit, not including advertising and the incentive. According to ARCA,
transportation costs vary only by about $10 to $20 per unit from any location in the continental
U.S.
Refrigerator recycling programs can be administered for a levelized cost of conserved energy (CCE)
between $0.03 and $0.05/kWh.k In general, levelized CCE is lower in the early years of program
implementation when there is a higher percentage of retired secondary units that are not replaced.
Long-running programs like Southern California Edison's have shown a gradual decline in cost-
effectiveness as the average age of collected refrigerators decreases and the percentage of units
being replaced increases.19
3.5.6. Program Examples
• Connecticut Light & Power (CL&P) and United Illuminating (Ul), Connecticut: CL&P
and Ul ran a successful joint appliance recycling program from 2004 through 2006. The
demand reduction attributable to the program was over 4 MW.20
• Southern California Edison (SCE), California: SCE has run appliance recycling programs
since 1994. From a residential customer base of 4 million, SCE achieves an annual
recycling volume of around 50,000 units per year.21 In 2002, the program recycled 43,000
units, reducing peak demand by over 12 MW.22 Program Web site:
http://www.sce.com/RebatesandSavinqs/Residential/ Appliances/RefriqeratorandFreezerRecyclinq/.
i Peak demand impacts based on evaluation data from AmerenUE, CL&P/UI, SCE, PG&E, SDG&E, SMUD, Nevada Power,
and Sierra Pacific Power.
keSource estimates are based on data from Fort Collins Utilities, Nevada Power, Sacramento Municipal Utility District, Southern
California Edison, and Utah Power.
U.S. Environmental Protection Agency 3-22 September 2008
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Energy Efficiency
3.6. PC Power Management
3.6.1. Overview
Computers account for over 1 percent of the ,,.,,., „«„
nation's commercial electricity usage, and H'9h"9hts: PC P™" Management
EPA estimates that half of all energy used to
power personal computers (PCs) is wasted.
In a typical building, office equipment
accounts for about 18 percent of electricity
use, with PCs accounting for more than half of
that equipment plug load.23 Computers (CPU,
Demand reduction: Approx. 1 kWper 150 PCs.
Technologies: Software that reduces monitor and
computer power use when inactive.
Cost effectiveness: $0.01-0.02/kWh.
ENERGY STAR information at:
www.enerqvstar.gov/powermanaqement.
hard drive, etc.) use roughly 60 to 70 watts
when active. Flat panel LCD monitors use
around half the power of computers when active. Power management, a feature available on all
computers and monitors, automatically places inactive PCs into a low-power sleep mode—
where the monitor and computer will draw only 1 to 3 watts each. PCs quickly wake up from
sleep with a wiggle of the mouse or touch of the keyboard.
Roughly 80% of monitors have power management settings already activated. However, only 5
to 10 percent of computers are power managed. Since computers use twice the power of LCD
monitors and are rarely power managed, EPA recommends activating power management on
both the computer and monitor—and not just the monitor only—to maximize your savings.
Overall, EPA estimates that if all office computers and monitors in the U.S. used their power
management feature, the country could save more than 44 billion kWh of electricity, equivalent
to the greenhouse gas emissions of 5 million cars each year.
In areas with large numbers of commercial office buildings, programs can achieve peak demand
reductions by helping businesses manage the way they operate their computers. Savings can
often be accomplished at low to moderate cost through network tools that can activate power
management settings simultaneously on every computer in a network. PC power management
also offers real cost-savings opportunities for businesses. Monitor power management (MPM)
saves $10-30 per monitor annually, and computer power management (CPM) saves an
additional $15-45 per desktop computer annually. Reducing PC energy use also helps to
reduce the internal heat load in commercial offices, creating additional savings from cooling load
reductions. Providing businesses with additional information on purchasing options for a host of
other ENERGY STAR qualifying products for the office (including computers, monitors, printers,
copiers, televisions and electronics) provides an additional value-added service and helps avoid
lost opportunities for peak demand reduction.
3.6.2. Best Practices
At a minimum, energy efficiency programs promoting PC power management entail targeted
outreach and education efforts. Programs can be education-only, informing customers about
the benefits of PC power management and referring them to ENERGY STAR tools and
resources. Programs can also provide a higher level of technical support and incentives for
implementing power management protocols where appropriate.
Programs must have the capacity to discuss energy savings opportunities at a top level with
business managers as well as the technical knowledge to communicate options and
opportunities to IT managers. Technical expertise that contribute to successful power
U.S. Environmental Protection Agency 3-23 September 2008
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Energy Efficiency
management efforts include: 1) Making available solutions to accommodate waking up sleeping
computers at night for updates, and 2) Advising network administrators on the appropriate
network tool option to activate power management on their specific network environment.
Targeting sites with more than 500 computers increases cost-effectiveness of outreach efforts,
although direct mail and online tools have been used successfully for smaller businesses and
residential customers. Other elements of success include management support for energy
efficiency improvement, a well-managed and proactive IT department, and the capacity and
motivation to effectively communicate the benefits of PC power management to computer users.
3.6.3. Barriers
IT departments regularly deactivate power management features when setting up new PCs
because they update computers at night or had bad experiences when CPM was much more
unstable. IT departments must be convinced that power management is a sound technology
and be presented with solutions to ensure that sleeping computers do not interfere with the
nighttime distribution of administrative software updates. For these reasons, it is important for
energy efficiency programs to have a high level of technical capability so they can communicate
effectively with IT staff and change standard practice.
3.6.4. Peak Demand Impacts
Though savings (kWh) per computer are relatively well-documented, there are fewer data on the
peak demand impacts (kW) attributable to PC power management programs. (A study is
currently underway at a Seattle utility to quantify the peak demand impacts of PC power
management.) Key factors affecting savings include how computers are currently used—
nighttime shut downs, work patterns, and whether monitor power management is already in use.
For example, if each computer uses 70 watts and 10 percent of them enter low-power sleep
mode (a conservative estimate) during peak demand periods, then power managing around 150
computers saves 1 kWof peak demand.
3.6.5. Cost-Effectiveness
PC power management programs can be implemented within a short time horizon. Businesses
need to simply activate existing features on their PCs. Power management programs offer a
good opportunity to reduce load during peak times on relatively short notice. In the past,
programs that promoted and implemented power management of only the monitor typically
achieve a levelized CEE of $0.01 to $0.02/kWh.' Outreach and education-only programs are the
lowest-cost, but it is more difficult to verify the savings associated with these programs.
Programs that provide a higher level of technical support services incur costs between $0.01
and $0.06/kWh, or $5-30 per computer. Monitoring and verification activities increase program
costs. There are also some costs to the customer in terms of the time internal IT staff spend on
power management projects.
3.6.6. Program Examples
• Avista Utilities, Washington: Avista provides an incentive of $10 per controlled PC for
software that enables a centralized approach to power management and which meets
utility-specified minimum criteria. Program Web site:
http://www.avistautilities.com/saving/conservation/power management.asp.
EPA estimates based on data from NYSERDA and PG&E.
U.S. Environmental Protection Agency 3-24 September 2008
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Energy Efficiency
Pacific Gas & Electric Company (PG&E) and the Association of Bay Area
Governments (ABAC), California: PG&E and ABAG partnered to promote CPM,
providing free materials and information to ABAG member agencies. Technical
consultants hosted conference calls to help agencies identify the best path to CPM
giving their unique IT environments. PG&E offered an incentive of $10 per controlled PC
to association members, regardless of the CPM solution implemented.
Northwest Energy Efficiency Alliance (NEEA): In 2001, NEEA formed a partnership
with Verdiem, Inc. to commercialize the Surveyor Network Energy Manager software,
which enables network operators to remotely turn off PCs and enable pre-installed
power management software on networked computers. NEEA provided matching funds
to support Verdiem's marketing efforts. A 2005 program evaluation verified savings of
around 200 kWh per PC, but did not evaluate peak demand impacts. Program Web site:
http://www.nwalliance.org/ourwork/proiectsummary.aspx?ID=65.
U.S. Environmental Protection Agency 3-25 September 2008
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Energy Efficiency
3.7. Commercial Lighting, Cooling, and Refrigeration
3.7.1. Owen/iew
In the commercial sector, which comprises I ...... IJL n~... , . n ,. „
about 35 percent of all retail electricity sales in H'9h"9hts: Commeraa/ W«g, Coolmg &
the U.S. , lighting and cooling represent key
areas of opportunity for peak demand ' Demand reduction:
reduction. Lighting consumes approximately 23
percent of the electricity used in commercial
buildings and is a primary source of heat gain
and waste heat. On average, cooling accounts
for about 26 percent of electricity use in
commercial buildings and an even larger kW/participant for large C&l programs.
• Technologies: Efficient lighting, HVAC, and
percentage in warm climates. On a national
basis, offices, retail spaces, warehouses, and
schools are the largest consumers of electricity applications.
for commercial lighting and HVAC, and are
Refrigeration
Lighting: 1-7 kW/participant for small
commercial programs, and 20-35 kW/
participant for large C&l programs.
HVAC: 0.6-1 kW/participant for small
commercial programs, and -200
refrigeration equipment for commercial
Cost effectiveness:
o Lighting programs: $0.005-$0.02/kWh.
o HVAC programs: $0.01-$0.06/kWh.
likely to be strong initial targets for commercial
retrofit programs. Refrigeration represents
around 9 percent of commercial energy use,
and programs have achieved peak demand
reduction by promoting energy-efficient refrigeration in targeted segments of the commercial
market such as grocery stores and food service establishments.
3.7,2,
Prescriptive incentive programs are a proven strategy to capture savings from efficient lighting,
cooling, and refrigeration measures across a range of non-residential sectors. Such programs
offer pre-determined incentives for a range of common energy efficiency measures for which
per-measure energy savings can be readily estimated. To maximize market impact, prescriptive
programs are typically trade ally-driven, and might involve manufacturers, distributors,
equipment vendors and installers, and energy service providers. Such programs minimize
barriers to participation through simple application processes and rapid incentive processing.
Due to their straightforward design and implementation approach, prescriptive incentive
programs can also be ramped up quickly, and are the basic building blocks of virtually every
energy efficiency program portfolio.
Major program elements typically employed by energy efficiency program administrators
include:
• Prescriptive incentives that cover a portion of the incremental cost of installing a higher
efficiency technology, with many programs setting incentive levels to ensure payback in
one to two years.
• Incentive structures linked to ENERGY STAR specifications and performance
thresholds, when available.
• Program marketing via trade allies such as lighting and HVAC vendors and contractors.
Regular communication with trade allies allows program administrators to address
issues as they arise and ensures allies are actively engaged in promoting the program.
U.S. Environmental Protection Agency 3-26 September 2008
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Energy Efficiency
In some cases, trade ally incentives are offered to motivate sales of qualifying
equipment.
• Additional marketing and outreach to end users conducted through business and
industry trade associations, as well as direct solicitation by mail and telephone.
• Straightforward incentive application processes, with some utilities offering online rebate
application and processing.
• Streamlined verification/quality control processes to facilitate ease of participation and
minimize the time required for incentive payment.
• Simple tools and calculators to help customers understand the benefits of investing in
energy efficient technologies and to help trade allies sell high efficiency products by
clearly demonstrating payback period and lifetime savings benefits.
Although prescriptive programs are an excellent starting place for capturing peak demand
reduction opportunities in the commercial sector, a multi-faceted program approach might be
needed to capitalize on all opportunities for peak demand reduction. To capture a larger
amount of energy efficiency potential and serve a broad range of end-users, a program
administrator might choose to include prescriptive, custom, and targeted market program
elements in the initial energy efficiency portfolio, or establish the necessary market presence
with a prescriptive program before launching more complex program designs in subsequent
years.
Lighting
To promote optimal efficiency in commercial lighting design, some best practice programs
employ incentives based on energy savings or demand reduction (per kWh or kW). Though
prescriptive per-fixture incentive programs are simple to administer, they are less effective in
promoting optimal lighting design (for example, they do not address energy savings that could
be achieved through delamping). Though savings-based incentives increase administrative
complexity (particularly in terms of measurement and verification requirements), such
approaches seek to optimize energy use in a given space, enabling customers to achieve the
benefits of improved lighting quality as well as energy savings.
Cooling
In the case of HVAC systems where proper sizing and installation greatly improves
performance, a quality assurance plan helps to ensure proper design and installation. Proof of
proper sizing might be required as a condition of the rebate. For packaged HVAC units used in
smaller commercial applications, programs have developed clear quality assurance standards
and provided on-site verification using a sampling approach to verify performance. For larger
units, some programs offer commissioning assistance and incentives to ensure proper function.
Refrigeration
A broad prescriptive program might not be an effective mechanism for reaching niche market
segments such as grocery and food service establishments. Targeted market programs can
employ financial value messaging and implementation strategies that are designed to have
maximum efficacy in niche market segments. In addition, small businesses and other hard-to-
reach market segments often face barriers to participation in efficiency programs that are more
U.S. Environmental Protection Agency 3-27 September 2008
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Energy Efficiency
severe or complex than those addressed by mainstream program design. Some program
administrators include specialized programs designed to target hard-to-reach customer
segments where a specific delivery approach is needed to overcome market-specific
participation barriers. Common approaches employed by such programs include grassroots
outreach strategies, higher incentive levels, on-bill financing mechanisms to help customers
finance costs not covered by incentives, and direct installation of low-cost measures such as
refrigerator/freezer door gaskets, strip curtains for walk-ins, or anti-sweat heater (ASH) controls.
3.7.3. Barriers
Prescriptive incentive programs might fail to realize savings that are associated with more
complex measures or with systems that include multiple technologies. For example, a facility
that is evaluating equipment for a cooling system upgrade might not consider how implementing
a lighting system upgrade would reduce cooling load and potentially allow for down-sizing of
cooling equipment. A balanced energy efficiency portfolio will also include programs to promote
more comprehensive assessments of facility energy use and cross-cutting energy efficiency
opportunities (see Section 3.8 for a discussion of whole building energy performance programs
for the commercial market). Proven models include custom incentive programs that offer a
greater degree of technical assistance and incentives based on calculated energy savings
and/or demand reduction. Design assistance programs offer similar mechanisms to promote
energy efficient design and construction of commercial facilities (new construction or major
renovations).
3.7.4. Peak Demand Impacts
Prescriptive incentive programs for the commercial market vary in terms of peak demand
impacts per customer depending on the technologies promoted and market segments
addressed. Section 3.1 presents measure-level demand reduction data compiled by ACEEE.
At the program level, lighting programs for the small commercial market have achieved demand
reduction impacts ranging from 1 to 7 kWper participant, and lighting programs targeting large
commercial and industrial (C&l) customers have achieved demand reduction impacts ranging
from 20 kWto 35 kW.26 HVAC programs targeting tuneups and small commercial applications
have achieved demand reductions of 0.6 kWto 1 kW per participant. An HVAC program
promoting energy efficient water-cooled chillers for the large C&l market implemented by the
Los Angeles Department of Water & Power achieved demand reductions of over 200 kW per
participant.27 For refrigeration measures, a statewide program in California targeting efficient
refrigeration and lighting for independent grocery stores achieved peak demand reductions of
10 kW per participant.28
3.7.5. Cost-Effectiveness
Prescriptive commercial lighting and HVAC programs have been market-tested and proven to
be cost-effective across the country. Prescriptive programs targeting commercial lighting report
a levelized CCE between $0.005 and $0.02/kWh.29 Prescriptive programs targeting commercial
HVAC systems report a levelized CCE between $0.01 and $0.06/kWh.30 As savings associated
with HVAC systems are highly dependent on base usage levels, HVAC programs are more cost
effective in severe climates than in mild ones.
U.S. Environmental Protection Agency 3-28 September 2008
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Energy Efficiency
3.7.6. Program Examples
• Xcel Energy, Minnesota: Xcel's Lighting Efficiency Program offers prescriptive and
custom incentives to promote energy-efficient lighting retrofits in existing commercial
buildings and energy efficient lighting design in commercial new construction. The
program employs higher incentive levels for small commercial customers. In 2006, the
program completed nearly 300 lighting retrofits and achieved an average peak demand
reduction of 12 kW per customer (program-reported gross savings).31 Program Web site:
http://www.xcelenergy.eom/XLWEB/CDA/0.3080.1-1-3 4530 39021 40437-779-
5 538 969-O.OO.html.
• Northeast Energy Efficiency Partnerships (NEEP): NEEP developed Cool Choice as
a regional implementation model for energy efficiency program sponsors targeting
retrofits of commercial HVAC equipment. Until the adoption of new federal efficiency
standards (set to take effect in 2010) the program offered technical assistance and
incentives for the installation of packaged HVAC units (up to 30 tons in capacity) that
met CEE Tier 2 efficiency standards. Local program sponsors include the Long Island
Power Authority (LIPA), NSTAR, Efficiency Vermont and Efficiency Maine. In 2002, the
program served 3,200 customers and achieved 3.5 MWof peak demand reduction.32
Program Web site: http://www.neep.org/initiatives/Comm HVAC.html.
• Pacific Gas & Electric Company (PG&E), California: The EnergySmart Grocer
program provides information, technical assistance, and incentives to promote energy
efficient refrigeration, lighting, and HVAC equipment for independent food retailers.
Program incentives include direct installation of low-cost measures as well as
prescriptive rebates for more capital-intensive measures. Although at one point the
program was jointly administered as a statewide program by the four major investor-
owned utilities in California, it is now offered only by PG&E. An evaluation of the
statewide program for 2004-2005 assessed annual peak demand impacts at 12.7 MW.
Wth around 1,300 retrofits completed over that period, the program achieved peak
demand reductions of almost 10 kW per customer.33 Program Web site:
http://www.energysmartgrocer.org/.
U.S. Environmental Protection Agency 3-29 September 2008
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Energy Efficiency
3.8. Whole Building Energy Performance for the C&l Market
3.8.1. Overview
Commercial building energy use is a leading I T~77~! .„,, , „ .,,. ~
component of peak energy demand. Typical H'9h"9hts: Whole Buildl"9 Performanc*
Demand reduction: 16-600 kW per participant.
Technologies: Efficient lighting, HVAC, motors
and drives, process retrofits, and commissioning
services.
Cost effectiveness: $0.01 - 0.04/kWh.
ENERGY STAR information at:
www.enerqvstar.gov/buildinqs.
commercial building energy efficiency programs
provide rebates to upgrade specific equipment.
While these technology-specific incentives have an
important role in building markets for energy
efficiency, taking a more comprehensive
approach—looking at interactions of energy end-
uses and overall building performance—allows for
energy efficiency programs to capture much
greater savings. Over the past 25 years, the
energy efficiency of building components such as windows and chillers has improved by more
than 30 percent; yet, building energy efficiency has not improved by nearly as much. This result
reflects the significant role that proper sizing of heating and cooling equipment, integrating
individual technical components and controlling, operating and maintaining equipment can have
in determining the energy performance of a building.
A whole building energy performance approach moves beyond traditional energy efficiency
programs focused on individual measures or end uses. EPA estimates that the energy
consumption of commercial and industrial buildings can be reduced by up to 30 percent through
whole-building strategies that address improved operations, maintenance practices, and
comprehensive upgrades to building equipment.
In the C&l sector, lack of knowledge about overall building energy performance is a key barrier
to motivating building owners and operators to implement comprehensive energy efficiency
improvement projects. To address this obstacle, EPA created an energy performance rating
system that compares the energy use of an individual building against the national stock of
similar buildings using a 1 to 100 point rating system. This rating enables building owners and
managers to measure how well building systems are integrated, operated, and maintained. The
EPA rating has a clear role to play in any comprehensive program design by providing a
standardized metric for whole-building performance. Use of the performance rating also allows
program administrators to establish a valuable link to the ENERGY STAR program platform for
the commercial market.
3.8.2. Best Practices
There are two primary program strategies for capturing the peak demand reduction
opportunities associated with whole building energy performance improvement. Each strategy
is designed to take a comprehensive approach to assess energy savings opportunities in C&l
buildings, although each has a different primary focus. One strategy focuses on operations,
maintenance, and low cost equipment improvements through retrocommissioning (RCx)
building systems. The other strategy employs comprehensive, customized approaches to target
capital retrofit improvements.
• RCx programs: RCx is an emerging energy efficiency program design in the U.S. that
improves the operating efficiency of buildings that do not require immediate capital
improvements to replace or repair equipment. The RCx process ensures that building
U.S. Environmental Protection Agency 3-30 September 2008
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Energy Efficiency
systems such as HVAC equipment and control systems are operating at optimal
efficiency in accordance with design specifications. Demand and energy savings are
realized through the systematic evaluation of building systems and the implementation of
low-cost measures designed to improve system operations and, in many cases, improve
occupant comfort.
• Comprehensive retrofit programs: These programs are designed to promote a
comprehensive assessment of energy efficiency retrofit opportunities across multiple
building systems. Common features include walk-through energy audits and a high level
of technical assistance. Technical assistance is usually provided on a cost-share basis
to ensure customer investment in the process, and might include training on
benchmarking energy use with the EPA rating system, energy modeling, and financial
feasibility studies of energy efficiency retrofit opportunities. Comprehensive retrofit
programs employ a variety of incentive strategies, including custom incentives based on
kW or kWh reductions, standard offer contracts, and bidding processes.
EPA's energy performance rating system supports both program strategies. In addition to
increasing customer motivation to participate in existing energy efficiency programs and/or
otherwise pursue improvements in energy efficiency, promoting the use of the EPA rating
through early educational and informational efforts can help lay the foundation for more
comprehensive improvement approaches. Program administrators have incorporated the EPA
rating as their energy use intensity benchmark for retro-commissioning programs and whole-
building benchmarking and upgrade programs.
3.8.3. Barriers
Whole building energy performance programs are generally more complex to administer than
prescriptive rebate programs, and are most commonly implemented by program administrators
with an established record of energy efficiency initiatives. Less experienced program
administrators might begin with traditional prescriptive programs and gain experience with more
comprehensive approaches on a small-scale pilot basis. In order to capture a larger amount of
energy efficiency potential and serve a broad range of end-users, a mature energy efficiency
portfolio will typically include a mixture of prescriptive and comprehensive program approaches
for the C&l market.
Such programs may also encounter more substantial barriers to participation as they require a
higher level of effort on the part of the customer/trade ally. In some markets, there may be few
trade allies qualified to implement more comprehensive energy efficiency improvement projects.
NYSERDA and National Grid have invested resources in developing networks of qualified trade
allies through screening and training activities.
Lastly, whole building approaches typically require more measurement and verification (EM&V)
M&V resources to verify peak demand impacts. Where prescriptive programs can employ
deemed savings estimates due to the standardized nature of the energy savings measures they
promote, custom programs often require a greater number of on-site assessments as well as
some post-installation metering and verification because of the non-standard nature of the
measures covered, interactive effects (e.g., between lighting and HVAC systems), and project
size.
U.S. Environmental Protection Agency 3-31 September 2008
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Energy Efficiency
3.8.4. Peak Demand Impacts
There is a wide range in the peak demand impacts attributed to programs promoting whole
building energy performance improvement. Comprehensive programs serving the large C&l
market have achieved peak demand reductions of 16 to 300 kWper participant.34 Retro-
commissioning programs show a similar range in demand reduction impacts depending on the
nature of targeted facilities and the extent of commissioning services provided, with programs
reporting reductions between 17 and 600 kW per participant.35
3.8.5. Cost-Effectiveness
Programs leveraging the ENERGY STAR platform to promote comprehensive whole building
energy performance are delivering substantial energy savings for a levelized CCE of $0.03 to
$0.04/kWh.m A recent review of large comprehensive retrofit programs for the C&l market show
levelized CCE between $0.01 and $0.04/kWh.36
3.8.6. Program Examples
• NYSERDA, New York: NYSERDA has been a leader in developing comprehensive
approaches to whole building performance improvement and has integrated the EPA
energy performance rating system rating into several of its programs—New York Energy
$mart Schools, the Retro-Commissioning Pilot, Healthcare Facility Benchmarking, and
the recently launched Enhance Commercial/Industrial Performance Program. Without
investment in major capital equipment improvements, NYSERDA estimates that RCx
projects can reduce building energy demand (kW) by 5 to 7 percent, with typical energy
consumption savings (kWh) ranging from 5 to 20 percent. Program Web site:
http://www.nvserda.org/Programs/Commercial Industrial/cipp.asp.
• CL&P, Connecticut: CL&P has two programs that promote whole building energy
performance in the C&l market. The Operations & Maintenance program provides
incentives for RCx services and other O&M improvement opportunities, and also offers a
Building Operator Certification training program to promote ongoing O&M best practices.
In 2006, the program achieved demand reductions of 27 kW per participant. Energy
Opportunities is a comprehensive program that provides prescriptive and custom
incentives as well as technical assessments of energy efficiency retrofit opportunities in
existing buildings. In 2006, the program achieved demand reductions of 30 kW per
participant.
o O&M Program Web site: http://www.cl-p.com/clmbus/target/OandM.asp.
o Energy Opportunities Program Web site:
http://www.cl-p.com/clmbus/target/custom.asp.
• NSTAR, Massachusetts: Since 2003, NSTAR has assessed whole building energy
performance in over 70 buildings, totaling 16 million square feet of floor space. NSTAR
uses the EPA performance rating system and other ENERGY STAR tools to educate
customers about the overall performance of their buildings and to help them identify and
prioritize energy efficiency upgrades. NSTAR also provides prescriptive and custom
incentives through the Business Solutions Program. Approximately 50 percent of
' Estimates based on data from Northeast Utilities (CL&P and Ul); NSTAR, and SCE.
U.S. Environmental Protection Agency 3-32 September 2008
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Energy Efficiency
customers that benchmark their buildings have taken action to improve energy
performance, with many taking advantage of prescriptive and custom incentive offerings.
Program Web site:
http://www.nstaronline.com/business/energy efficiency/electric programs/benchmark.asp.
U.S. Environmental Protection Agency 3-33 September 2008
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Energy Efficiency
Highlights: Cool Roofs
Demand reduction: 0.19-0.4 kWper 1000 sq. ft.
Technologies: Roofing materials with high
reflectance and surface emittance.
Cost effectiveness: $0.03-0.11/kWh.
ENERGY STAR information at:
http://www.enerqystar.qov/index.cfm?c=r
oof prods.pr roof products.
3.9. Cool Roofs
3.9.1. Overview
Energy-efficient roofing systems—also called "cool
roofs"—can reduce roof temperature by as much as
100°F on hot summer afternoons, lowering cooling
energy requirements and peak energy demand.
Additional benefits associated with cool roofs
include increased comfort for building occupants
and greater durability as cool roofs are less subject
to damage from ultraviolet radiation and daily
temperature fluctuations. ENERGY STAR qualified
roof products can help reduce the amount of air
conditioning needed in buildings and can lower
peak cooling demand by 10-15 percent.
The typical cost premium for a cool roof is less than $0.20 per square foot, and may be as low
as zero.
3.9.2. Best Practices
There are two primary strategies to achieve the peak demand reductions associated with cool
roofs: building codes that establish cool roof requirements and energy efficiency incentive
programs.
Building codes
California is a leading example of the use of building codes to promote cool roofs, as the state
incorporated cool roofs into its "Title 24" Building Energy Efficiency Standards in 2005." These
requirements apply to conditioned (heated or cooled) nonresidential buildings that have low-
sloped roofs. This includes newly constructed buildings and re-roofing of existing buildings.
Title 24 does not require that building owners replace or recover existing roofs that are not in
need of re-roofing.
Title 24 offers builders the option of following a prescriptive or performance approach to
complying with their energy budget. Title 24 standards are developed and promulgated by the
California Energy Commission (CEC), but local building departments are responsible for
enforcing the cool roof requirements. The CEC maintains a Title 24 Hotline, offers training at
meetings of local building officials, and provides onsite training upon request. California's
electric and gas utilities also sponsor training sessions for local building departments on
compliance options. For a cool roof product to be eligible to qualify under the Title 24
standards, it must be tested and rated through the Cool Roof Rating Council (CRRC). Cool roof
manufacturers offer products for both low-slope and sloped roofs.
California has a long history of advancing cool roofs as a peak demand reduction measure.
Related education and outreach programs are effective at reaching customers, retailers, and
suppliers. The CEC's Consumer Energy Center offers a database of cool roof products, FAQs,
n Additional details on California's cool roof requirements under Title 24 are available at:
http://www.consumerenerqvcenter.org/coolroof/.
U.S. Environmental Protection Agency
3-34
September 2008
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Energy Efficiency
print material, videos, and a comprehensive Web site. Experts from the Lawrence Berkeley Lab
(LBNL) and CEC frequently participate in peer exchange forums. Research by LBN Us Heat
Island Program demonstrates that reductions in building cooling electricity use, peak power
demand, and ambient air temperature are all possible from cool roofs in California. However,
much of this research is location-specific, and other states may be interested in conducting their
own analysis.
Incentive programs
Cool roof incentive programs have proven to be cost-effective strategies for achieving energy
savings and peak demand reduction, particularly in regions with substantial cooling loads.
Programs are typically trade ally-driven, providing incentives to roofing contractors for the
installation of qualifying product in eligible facilities. Contractor outreach and training is
recommended to develop a network of installers promoting qualified products to their
customers. To maximize savings, programs typically establish requirements on the types of
facilities that are eligible for incentives (e.g., commercial facilities with low- or no-slope roofs,
etc.). Adequate roof insulation also plays an important role in reducing cooling-related building
energy consumption, and some programs offer incentives for roofing and ceiling insulation as
well as cool roofs.
3.9.3. Barriers
Cool roof incentive programs are not cost-effective in all areas. Building code requirements
may be a more effective strategy in milder climate regions. Where cool roof programs are cost-
effective, it is important to conduct verification of contractor work to ensure that program
requirements are being met.
3.9.4. Peak Demand Impacts
DOE conducted building energy simulations to demonstrate the savings associated with the use
of a cool roofing material on a prototypical California nonresidential building with a low-sloped
roof. These simulations demonstrated significant electricity and gas savings on a unit-area
basis, as shown in Table 3-5.
Table 3-5. Cool Roof Savings
Savings Category Average Savings
per 1000 sq. ft.
Annual electricity savings 297 kWh
Annual natural gas savings 4.9 therms
Annual source energy savings 2.6 MBtu
Peak demand reduction 0.19 kW
Cooling equipment cost savings $94
Fifteen-year net present value (NPV) of energy savings $451
Total cost savings $545
(cooling equipment cost savings + 15-year NPV energy savings)
U.S. Environmental Protection Agency 3-35 September 2008
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Energy Efficiency
Energy efficiency programs have achieved peak demand reductions of 5 kW per participant and
0.4 kW per thousand square feet.0
3.9.5. Cost-Effectiveness
Cool roof incentive programs will be most cost-effective in areas with substantial cooling loads.
Cool roof programs reviewed in this assessment show a levelized CCE between $0.03 and
$0.11/kWh.p
3.9.6. Program Examples
• Austin Energy, Texas: Austin Energy has offered a cool roof program since 2002, and
currently provides commercial customers with incentives of $0.15 per square foot. From
2002 through 2005, the program achieved 680 kW of peak demand reduction by
providing incentives for $1.6 million square feet of cool roofs.37 Program Web site:
http://www.austinenergv.com/Energv%20Efficiencv/Programs/Rebates/Commercial/Com
mercial%20Energv/ceilingRoof.htm.
• Sacramento Municipal Utility District (SMUD), California: SMUD launched a
successful cool roof incentive program in 2001 in an effort to increase market
penetration of highly reflective and emissive roofing products in the commercial retrofit
and new construction markets. The program was contractor-driven, providing roofing
contractors with incentives on a square-foot basis for the installation of ENERGY STAR
qualified roofing products. Cool roofs installed on commercial or multifamily residential
buildings were eligible for incentives if the buildings were air conditioned and had no-
slope roofs. Through 2002, the program achieved demand reductions of 5 kW per
participant.38 The program was discontinued at the end of 2005 once cool roofs became
mandated by Title 24 standards. Program Web site:
http://www.smud.org/rebates/cool%20roofs/.
Based on program data from Austin Energy and SMUD.
Based on program data from Austin Energy and SMUD.
U.S. Environmental Protection Agency 3-36 September 2008
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4. Demand Response
4.1. Introduction
The broad term "Demand response" encompasses a range of program types designed to
reduce electricity use during peak demand periods. Demand response programs are typically
designed to increase system reliability and/or minimize the use of peaking units that are usually
among the most expensive and most polluting sources of power. At the retail level, demand
response programs are typically implemented by utilities or other load-serving entities (LSEs).
At the wholesale level, independent system operators (ISOs) or regional transmission
organizations (RTOs) might also provide incentives to LSEs for the aggregated demand
reductions of retail customers. Demand response initiatives range from programs that provide
customer incentives for voluntary (nonfirm) or mandatory (firm) load curtailment, to dynamic
pricing structures that charge higher rates during peak periods, employing a market-based
approach to achieving peak demand reduction.
Some administrators of demand response programs are finding that a portfolio of demand
response programs comprised of voluntary and mandatory reduction commitments is the most
cost-effective demand response strategy. This approach also offers customers increased
flexibility in terms of selecting the demand response option that is best suited to their risk
tolerance. A recent assessment of demand response programs by the Federal Energy
Regulatory Commission (FERC) notes that multiple demand response offerings can serve
complementary goals. For example, large-scale implementation of time-based rates reduces
the severity or frequency of reserve shortages, which in turn reduces the need for mandatory
curtailments. Reductions in the frequency of curtailment events may also boost participation in
incentive-based mandatory curtailment programs by reducing the risks associated with frequent
curtailment events.39
A variety of enabling technologies reinforce demand response objectives. Advanced metering
and communications infrastructure transmits hourly (or even more frequent) data on customer
energy use to the LSE, which is necessary to support dynamic pricing structures. Load control
devices such as smart thermostats or switches might be located at a customer's home or
business, permitting the LSE to remotely curtail their energy use. Smart thermostats and other
energy management devices also provide the customer with more detailed information on their
energy use, helping to motivate demand reductions when they are needed.
In order to serve as an effective strategy for reducing HEDD emissions, it is essential that
demand response initiatives be structured to avoid a net emissions increase through the use of
emissions-intensive sources of backup power generation. Some program administrators have
addressed this issue by including requirements for the types of load reductions that are eligible
for demand response incentives. Combining demand response with efforts to promote clean
forms of distributed generation can be another effective strategy for achieving this objective.
There is a growing appreciation of the complementary roles that demand response programs
and energy efficiency programs play to reduce peak demand, and a balanced approach to
demand-side management typically includes both types of initiatives. Moreover, these elements
should, to the extent possible, be integrated conceptually and programmatically to extract
maximum value from the demand-side resource.
The remaining sections in Chapter 4 discuss best practices for demand response incentive
programs and dynamic pricing programs.
U.S. Environmental Protection Agency 4-37 September 2008
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Demand Response
4.2. Incentive Programs
4.2.1. Overview
Incentive-based demand response programs ,,.,,.,„
provide incentives to electricity users who H'9h"9hts: ^mand Response Incentives
voluntarily reduce consumption during periods of
peak demand or allow their load to be directly
curtailed by the LSE or system operator. With
emergency demand response, curtailment is
Demand reduction: 0.6 kW to 1 kW per
participant for direct load control programs.
FERC Assessment of Demand Response &
Advanced Metering:
triggered when system generating or http://www.ferc.qov/leqal/staff-
transmission/distribution capacity is not sufficient reports/demand-response.pdf.
to meet demand. With economic demand
response, curtailment is triggered by high
wholesale prices for electricity. Participating customers typically reduce loads by switching to
backup generation or flexing facility loads (e.g., adjusting HVAC or lighting set points) manually
or through automated mechanisms controlled remotely by the program administrator. The net
emissions reductions achieved by demand response programs depend on which of these load
reduction options, or combination of options, is employed.
FERC estimates that the potential peak reductions from existing demand response incentive
programs are roughly 37,500 MW nationally and range from 3 to 7 percent of peak demand in
most regions.40
4.2.2. Best Practices
There are several common types of demand response incentive programs which differ by the
end use sector they target (e.g., industrial, commercial, or residential) and the type of event that
triggers their utilization (e.g., a system emergency or high wholesale prices). Common incentive
program types include:41
• Direct load control programs: According to the FERC study, direct load control
programs are one of the most common types of demand response programs. Direct
load control programs typically target the residential or small commercial markets and
employ switches or other technologies that allow the LSE or system operator to remotely
switch off or cycle equipment such as air conditioners, water heaters, or pool pumps
during peak demand periods. The customer usually receives an annual incentive
payment or bill credit for participating in the program. Administrators of direct load control
programs deploy increasingly sophisticated technologies to facilitate demand response,
from smart thermostats to home climate control systems that can be programmed through
a Web-based interface.
• Interruptible/curtailable rates: Interruptible/curtailable programs are a common
program model for the large commercial and industrial market, and offer a rate discount
or bill credit to customers that provide a specified amount of load reduction upon
advance notice by the LSE. Failure to curtail could mean the customer is subject to a
financial penalty, but the total number of curtailment hours that can be called upon
during a year is usually capped. Such programs typically target large customers with
demand of 200 kW or above, but are not well-suited for customers that operate 24 hours
a day or employ continuous manufacturing processes.
U.S. Environmental Protection Agency 4-38 September 2008
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Demand Response
• Demand bidding/buyback programs: Demand bidding programs also target large
commercial and industrial customers and enable participants to specify how much load
they would be willing to reduce at a given price or specify both the amount of load
reduction and the price. If the customer bids are the least expensive way of meeting
demand (e.g., costing less than the supply-side alternative), the load curtailment is
called upon and the customers must achieve the specified demand reduction. Such
programs are implemented both by LSEs and by system operators.
• Emergency demand response programs: Emergency demand response programs
provide incentives to customers for reducing load during reliability-triggered events, but
curtailment is voluntary. Though some LSEs implement emergency programs, they are
most commonly implemented by system operators (ISOs or RTOs).
• Capacity market programs: Under capacity market programs, commercial and
industrial customers commit to providing pre-specified load reductions during system
emergencies. As participants are subject to penalties for failure to curtail usage when
notified, capacity market programs represent firm load reduction commitments.
Incentives are paid annually, whether or not curtailment events are called. Programs are
typically administered by system operators (ISOs or RTOs).
4.2.3. Barriers
In order for demand response incentive programs to provide an effective strategy to reduce
HEDD emissions, it is essential that such programs be structured to avoid a net emissions
increase through the use of emissions-intensive sources of backup power generation.
According to a recent ISO New England report, a significant fraction of incentive-based demand
response came from the use of backup generation rather than curtailment.42 Demand response
programs that allow the use of backup generators to meet demand response obligations are
likely to compromise the environmental benefits of the programs. Programs targeting residential
and small commercial customers are unlikely to result in the use of backup generators, though
such programs also have smaller peak demand impacts than programs targeting the large
commercial and industrial market. Some program administrators have addressed this issue by
including requirements for the types of load reductions that are eligible for demand response
incentives. For example, New York Independent System Operator's Day Ahead Demand
Response Program prohibits the use of backup generation. As economic programs are more
likely to encourage load flexing, demand bidding initiatives could be a more appropriate
candidate for inclusion in a HEDD strategy than emergency demand response programs.
As utility revenues from large C&l customers are typically based on a combination of energy
consumption (kWh) and peak demand (kW) charges, addressing utility disincentives to
providing demand response programs is another important issue that is best addressed at the
regulatory policy level. States can ensure that utility incentives are aligned with well-functioning
demand response programs using similar approaches as those used to address disincentives to
energy efficiency investment, such as decoupling, cost recovery, and performance-based
incentives (see Section 2.2). As many demand response programs either require or are
significantly enhanced by advanced meters and/or devices that automate demand response
(e.g., smart thermostats), allowing utility cost recovery for these investments and providing
incentives to encourage such investments can be another important strategy.
Finally, demand response is best viewed as an important part of a portfolio approach to demand
side management that also includes energy efficiency and technical assistance. Important
U.S. Environmental Protection Agency 4-39 September 2008
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Demand Response
synergies will likely exist between the programs (e.g., technical assistance can help customers
identify appropriate load flexing opportunities).
4.2.4. Peak Demand Impacts
For direct load control programs serving the residential and small commercial market, the FERC
assessment reports a typical demand reduction of around 1 kWfor each air conditioner and
around 0.6 kWfor each water heater.43 However, FERC notes that actual demand reductions
vary by the size of the appliance controlled, customer energy usage patterns, and climate.
For demand response incentive programs targeting large C&l customers, there is substantial
variability in per-participant impacts. A cross-cutting evaluation of the demand response
programs offered by California lOUs showed that in 2005, participants in interruptible/curtailable
programs reduced baseline load by 58-78 percent, and participants in bidding programs
reduced baseline load by 9 percent.44
As estimates of demand response and subsequent payments are typically based on deviations
from an established baseline, rigorous evaluation, measurement, and verification protocols are
important to ensuring program effectiveness.
4.2.5. Cost-Effectiveness
The FERC assessment notes that one of the challenges facing broader deployment of demand
response programs is the lack of any standard procedure for the definition and evaluation of
cost-effectiveness. The cost-effectiveness tests used to evaluate energy efficiency programs
focus on avoided generation costs, and there is no standardized procedure for valuing the
market and reliability benefits that demand response programs entail. Though some ISOs and
RTOs include cost-effectiveness analysis in their yearly evaluations, there is no consistency of
approach to enable comparison.45 q
4.2.6. Program Examples
• Nevada Power Company Air Conditioning Load Management (ACLM) Project:
Nevada Power uses a variety of control devices in its direct load control program,
including one-way switches and smart thermostats. In 2005, the company deployed an
additional 5,000 switches and 1,000 thermostats, increasing the total number of active
load control units in the Las Vegas region to about 18,000. Nevada Power achieved
peak demand reductions of around 15 MW per curtailment event in 2005.46
• New York Independent System Operator (NYISO), New York: NYlSO's incentive-
based demand response programs include a capacity market program (SCR), a demand
bidding program (DADRP), and an emergency demand response program (EDR). In the
summer of 2003, 1,400 commercial, industrial, and multi-family residential customers
reduced their peak consumption by 700 MW. In the summer of 2006, NYISO called on
its EDR and SCR programs, which reduced peak demand by 1,100 MW. However,
DADRP is the only program that precludes customers from transferring loads onto on-
On behalf of the Demand Response Resource Center, Energy and Environmental Economics conducted an analysis of
challenges and data gaps that must be addressed in developing a standard practice for evaluation of demand response
programs in California. The report, Phase 1 Results: Establish the Value of Demand Response, is available at:
http://drrc.lbl.gov/pubs/60128.pdf.
U.S. Environmental Protection Agency 4-40 September 2008
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Demand Response
site generation to meet load reduction requirements. Program Web site:
http://www.nyiso.com/public/products/demand response/index.isp.
ISO New England (ISO-NE): ISO New England's incentive programs include its real
time demand response and capacity market (ICAP) programs. In order to participate,
customers must have an approved Internet-based communication system installed. In
2005, ISO-NE had 472.5 MW ready to respond, 290 MW of which was in Connecticut.
The program was called only once in 2005 and yielded 1,100 MWh, 870 MWh of which
was met with backup generation. Program Web site: http://www.iso-
ne.com/genrtion resrcs/dr/index.html.
U.S. Environmental Protection Agency 4-41 September 2008
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Demand Response
Highlights: Dynamic Pricing
Demand reduction: 5-15 percent in response to
high peak prices; greatest response with enabling
technology that automates demand response.
FERC Assessment of Demand Response &
Advanced Metering:
http://www.ferc.gov/legal/staff-
re ports/demand-response.pdf.
4.3. Dynamic Pricing
4.3.1. Overview
Dynamic pricing (also referred to as "time-based
rates") encompasses a variety of rate structures
where the price paid for electricity varies based
on the time of day. As wholesale power costs
fluctuate throughout the day based on time-
specific and location-specific conditions,
dynamic pricing structures promote demand
response through price signals that reflect the
underlying cost of production.47 At the same
time, dynamic pricing allows customers the
flexibility to decide whether to reduce consumption at times when prices are higher. While time-
based rates have commonly been used for large commercial and industrial customers, small
commercial and residential customers have historically paid flat electric rates based on the
average power production costs over time.
Where some kinds of demand response programs not well-suited to restructured (i.e.,
deregulated) electric markets, retail electric providers can successfully employ dynamic pricing
in both regulated and deregulated electric markets. As with incentive-based demand response
programs, participating customers can reduce loads during times of high prices by shifting loads
to other time periods, foregoing electricity use without making it up at another time, or switching
to backup generation. The elected option can have a significant impact on the resulting net
emissions impact.
4.3.2. Best Practices
Dynamic pricing structures fall into three general categories:48
• Time of Use (TOD) Pricing: A TOU rate is a daily rate structure that employs different
unit prices for electricity usage and/or demand during different blocks of time throughout
a day (e.g., peak, shoulder, and off-peak periods). TOU rates reflect the average cost of
generating and delivering power during those time periods.
• Critical Peak Pricing (CPP): CPP rates are designed to reduce energy use during
extreme peaks in demand and can be structured as an overlay on TOU or flat rates.
During a limited number of hours throughout the year, customers face a critical peak
price that is three to five times higher than the normal peak price under a TOU rate
structure. Customers receive notice of CPP events anywhere from a few hours or as
long as one day in advance.
• Real Time Pricing (RTP): RTP rates fluctuate hourly to reflect changes in the wholesale
price of electricity. RTP prices are typically known to customers on a day-ahead or hour-
ahead basis.
Figure 4-1 compares the three primary dynamic pricing structures:
U.S. Environmental Protection Agency 4-42 September 2008
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Demand Response
Figure 4-1. Comparison of Dynamic Pricing Structures
49
H-r-H-l..
In order for dynamic pricing structures to function effectively, the following conditions must be in
place: (1) customers need timely access to information about rate changes; (2) customers must
be capable of responding to price changes with automated load control systems facilitating
demand response; and (3) customers must have an advanced meter installed so that hourly
consumption data are available. Current estimates suggest that the market penetration of
advanced meters is low nationally—around 6 percent. However, market penetration of
advanced metering infrastructure is much higher in states such as Pennsylvania (52.5 percent)
and Connecticut (21.4 percent).50
Section 1252 of EPAct (Smart Metering) creates several requirements of utilities and utility
regulators with regard to time-based rates. By January 2008, each utility must offer time-based
rates to each of its customer classes, provide time-based rates to individual customers upon
request, and provide an advanced meter to each customer that requests time based rates. The
statute also directs states and utilities to consider the costs and benefits of demand response
programs and enabling technologies. Also by January 2008, in states that have not considered
implementation and adoption of a smart metering standard, the state public utilities commission
is required to issue a decision on whether to implement a standard for time-based rate
schedules.
51
4.3.3. Barriers
The type of customer response (e.g., shifting, foregoing, generating on site) to high peak prices
is likely to impact the environmental benefits of time-based rates and is a key consideration for
program design. In addition, dynamic pricing programs require advanced meters, are enhanced
by enabling technologies such as smart thermostats that provide customers with timely
information on electricity prices and consumption, and automate demand response by cycling
equipment and/or changing set points. Allowing utility cost recovery for these investments
and/or providing incentives to encourage such investments can be effective strategies to
support the use of dynamic pricing. However, disseminating technology is not often sufficient to
generate significant demand response. Providing technical assistance to help customers
develop response strategies is also important.
Time-based rates are best viewed as an important part of a portfolio approach to demand side
management that also includes energy efficiency, incentive-based demand response, customer
education, and technical assistance. As discussed previously, there are important synergies
between programs that can be leveraged to increase the effectiveness of the entire portfolio.
For example, time-based rates can encourage investments in peak-targeted efficiency by
providing the customer with a better signal of the true cost of electricity consumption during
peak periods.
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September 2008
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Demand Response
4.3.4. Peak Demand Impacts
The use of time-based rates, particularly CPP and RTP, is a relatively new development. Most
studies have found modest demand response to high peak prices (e.g., 5-15 percent), but
impacts vary significantly both within and between sectors. Preliminary results suggest that
government and education customers are most likely to forgo use, while industrial customers
are more likely to shift loads to off peak periods or utilize on-site generation. Commercial
customers have been largely unresponsive to price.
4.3.5. Cost-Effectiveness
As noted in Section 4.2.5, there is a general lack of standardized process to evaluate the cost-
effectiveness of demand response programs which makes comparisons between programs less
meaningful.52
4.3.6. Program Examples
• California lOUs: California conducted a statewide CPP pilot from 2003-04 which
included 2,500 customers from the industrial, commercial, and residential sectors. The
pilot found that residential customers were more price-responsive than commercial or
industrial customers, showing an average peak demand reduction of 12.5 percent.
Another key finding from the pilot program was that the enabling technologies such as
smart thermostats led to significantly higher levels of demand response. In 2005, the
lOUs' voluntary CPP tariff reduced peak demand by an average of 11 MW across
events. Load reductions were primarily achieved through process reductions and
curtailing discretionary uses rather than through backup generation.53
• Niagara Mohawk (now National Grid), New York: Niagara Mohawk has imposed a
mandatory RTP tariff for large customers (i.e., demand greater than 2 MW) since 1998.
A recent case study found that although approximately half of all customers in this class
were unable to adjust load, approximately one third of customers curtailed load without
shifting it to other periods, and around ten percent of customers both curtailed load and
shifted it to other time periods. The most common reduction strategy involved shutting
off equipment despite the fact that over half of the customers had demand response
enabling technologies that should have allowed for more sophisticated responses.
Government and educational facilities were found to have the highest price-
responsiveness, followed by industrial customers. Commercial customers were found to
be least responsive to price. Overall, the program represents about 50 MW in peak
demand reductions when the peak price is five times the off-peak price.54
U.S. Environmental Protection Agency 4-44 September 2008
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5. Distributed Generation
5.1. Introduction
Where energy efficiency and demand response initiatives represent demand-side approaches to
reducing peak electric demand and associated HEDD emissions, CHP and solar PV represent
opportunities for supplanting grid-supplied power with clean distributed generation (DG)
alternatives.
CHP (also known as "cogeneration") is the simultaneous production of electricity and heat from
a single fuel source, such as natural gas, biomass, biogas, coal, waste heat, or oil. CHP is not
a single technology, but an integrated energy system that can be modified depending upon the
needs of the energy user. CHP is more efficient due to the dual use of thermal and electric
energy, meaning that less fuel is required to produce a given energy output than if the heat and
power were generated separately. In addition, CHP systems are located onsite where the
energy is used, so they avoid the transmission and distribution losses that occur when electricity
travels over power lines from a central generating unit. CHP technology is well-suited for
energy-intensive facilities such as industrial plants; institutions such as colleges and
universities, hospitals, prisons, and military bases; large commercial buildings; municipal
facilities such as district energy systems and wastewater treatment plants; and multi-family
housing or planned communities.
Benefits associated with CHP include:
• Efficiency benefits: CHP requires less fuel to produce a given energy output, and
avoids transmission and distribution losses that occur when electricity travels over power
lines.
• Reliability benefits: CHP can be designed to provide high-quality electricity and thermal
energy to a site regardless of what might occur on the power grid, decreasing the impact
of outages and improving power quality for sensitive equipment.
• Environmental benefits: Because less fuel is burned to produce each unit of energy
output, CHP reduces air pollution and greenhouse gas emissions.
• Economic benefits: CHP systems can save facilities considerable money on their
energy bills due to their high efficiency and can provide a hedge against unstable energy
costs.
PV systems generate electricity from solar energy and are another form of clean DG that
displaces grid-supplied power. The solar resource is greatest on hot summer days when peak
electric demand is typically high, contributing to air quality benefits and also reducing strain on
the electric transmission and distribution system. Due to the modular configuration of PV
systems, solar electric technology can be utilized in a diverse range of settings, from urban to
rural and from small-scale residential to large-scale commercial applications.
Clean DG technologies face a unique set of policy barriers that demand-side resources do not
encounter. Sections 5.2 and 5.3 discuss policy best practices for addressing such barriers so
that clean DG can compete on a level playing field with traditional supply-side resources.
Sections 5.4 and 5.5 discuss incentive programs and other strategies that have been
successfully deployed to promote CHP and solar PV development, respectively.
U.S. Environmental Protection Agency 5-45 September 2008
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Distributed Generation
5.2. Standby Rates
5.2.1. Overview
DG resources like CHP and solar PV usually _ . „ _
supply only a portion of a facility's total electric Resources: Standby Rates
demand, so facilities typically remain grid-
connected. In addition, facilities that use http://www.epa.qov/chp/state-
renewables or CHP usually need to provide for policY/utility.html.
standby power when onsite generation is • New York Public Service Commission:
unavailable during periods of maintenance, http://www.dps.state.ny.us/.
EPA information on utility rates:
Oregon Public Utility Commission:
http://www.puc.state.or.us/.
California Energy Commission Distributed
Energy Resource Guide:
http://www.energy.ca.gov/distgen/.
equipment failure, or other planned outages.
Some electric utilities assess standby charges on
facilities with grid-connected DG in order to cover
the costs the utility could incur in providing
adequate generation, transmission, or
distribution capacity for intermittent service. The
rationale behind such charges is that the facility might require power at a time when electricity is
scarce or at a premium cost and that the utility must be prepared to serve load during such
extreme conditions. In some cases, such standby charges are excessive. Other rate practices
that affect the financial viability of grid-connected DG include demand ratchets and other electric
rates for backup power. Even in deregulated markets, sources must still pay demand charges
to access competitively-supplied backup power, and transmission and distribution tariffs
governing such charges might also employ rates that are unfavorable for DG.
The probability that all interconnected small-scale DG will need power at the same time is
relatively low. Consequently, in recent years several states have begun to evaluate utility rate
structures as part of their larger efforts to support cost-effective clean energy supply as an
alternative to expansion of the electric grid.
5.2.2. Best Practices
Based on state experiences to date with developing rate structures that support CHP and
renewable energy development, the following best practices can help other states implement
similar policies:
• Ensure that public utility commissioners and staff have current and accurate information
regarding rate issues for CHP and renewables, as well as the potential benefits that
clean DG could provide. These issues may not have been considered in the
development of rate structures that pre-date the more widespread application of
renewable energy and CHP technologies.
• If electric rate structures for clean DG cannot be addressed under an existing open
docket, utility commissions can open a generic docket to explore the actual costs and
system benefits of onsite clean energy supply and develop rate structures that ensure
cost recovery for utilities without creating undue financial obligations for onsite
generators.
• Coordinate with other state agencies that can lend support. State energy offices, energy
research and development offices, and economic development offices can be important
sources of objective data on actual costs and benefits of onsite generation.
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5.2.3. Best Practice Examples
Several notable examples of states with well-designed standby rate structures in place include
Oregon, California, and New York. These states ensure that standby rates allow CHP and
renewable forms of onsite generation to compete on a level playing field with traditional supply-
side resources and recognize the benefits of developing clean forms of DG while ensuring grid
reliability and providing adequate cost recovery for utilities.
Oregon
The Oregon Public Utilities Commission (PUC) outlined the following guidelines that should be
used to implement standby rates:
• Utilities should offer both firm and interruptible standby service. Rates should be
unbundled.
• There should be no inherent incentive for standby customers to idle their generators
when natural gas and wholesale power prices are high.
• Customers that have reliable control equipment to reduce loads instantly when their
generator goes off-line or reduces output should not have to pay for utility distribution
and transmission facilities, or reserves charges, based simply on the nameplate capacity
of the generator.
• Interruptible service should enable a customer to buy backup power on a short-term
basis, optimizing the economic operation of the generator. Energy rates for the
interruptible option should be market-based.
• Standby charges should not apply to customers with generating systems smaller than 1
MW. Variations in demand resulting from small systems going off-line at different times
are not noticeable to the system.
In 2004, the Oregon PUC approved a settlement regarding Portland General Electric
Company's (PGE) tariffs for customers that meet part of their energy requirements with onsite
generation ("partial requirements" customers)/ Under the settlement, the load served by onsite
generation is treated in the same manner as any other load on the system, which under Oregon
rules is obligated to have (or contract for) its share of contingency reserves. The onsite
generation is, in effect, both contributing to and deriving benefits from the system's overall
reserve margin. Under the new rates, the partial requirements customer must pay or contract
for contingency reserves equal to 7.0 percent (3.5 percent each for spinning and supplemental
reserves) of the "reserve capacity." Reserve capacity is defined as either the nameplate
capacity of the onsite generating unit or the amount of load the customer does not want to lose
in case of an unscheduled outage. If a customer is able to shed load when its onsite generating
unit goes down, then it will be able to reduce the amount of contingency reserves it must carry.
A similar standby pricing structure has been adopted by PacifiCorp.
An Oregon PUC staff report on distributed generation (February 2005) is available at:
http://www.oreqon.gov/PUC/meetinqs/pmemos/2005/030805/req3.pdf.
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California
California Senate Bill 28 1X passed in April 2001 and required the state's utilities to exempt DG
customers from standby reservation charges. The exemptions apply for the following time
periods:
• Through June 2011 for customers installing CHP-related generation between May 2001
and June 2004.
• Through June 2011 for "ultra-clean" and low-emission DG customers 5 MW and less
installed between January 2003 and December 2005.
• Through June 2006 for customers installing non-CHP applications between May 2001
and September 2002.
California utilities submitted DG rate design applications in September 2001. A docket was
opened to allow parties to file comments on the utilities' proposals in October and November
2001. After a year, the California Public Utilities Commission (CPUC) decided to incorporate
the rate design proposals into utility rate design proceedings, which means that there is no
uniform statewide standard. However, according to the California Energy Commission's
recently-released Distributed Generation and Cogeneration Policy Roadmap for California,
existing rules and regulations exempt most distributed renewable energy generating systems
from standby charges and departing load charges. CHP and other forms of clean DG are
exempt from standby charges and partially exempt from departing load charges.55
New York
In July 2003, the New York Public Service Commission (PSC) voted to approve new rates for
utilities' standby electric delivery service to DG customers, as well as to independent wholesale
electric generating plants that import electricity as "station power" to support their operations
(NYPSC Case 99-E-1470). A key objective of the new rate structure was to provide customers
with a clearer price signal for instances where onsite generation would provide a less expensive
alternative to grid-supplied power.56
The new standby rate structure employs a cost-based approach which recognizes that the
charges for providing delivery service to a standby customer should be based on the customer's
peak load (kW) rather than energy consumption (kWh). This approach is consistent with the
magnitude of transmission and distribution capacity needed to serve standby customers.
The New York PSC also established rules governing the transition of existing DG customers to
the new standby rates. Because the new rates were designed to better align the customer's
cost with the potential benefit of DG to the grid, in some cases it would be financially favorable
for customers with existing onsite generation to opt in immediately to the new rates, which
would also promote grid reliability. Recognizing the environmental benefits of certain forms of
DG, three transition options were given to customers that began onsite generation between
August 1, 2003, and May 31, 2006, with technologies such as small CHP applications (less than
1 MW) or "environmentally beneficial" technologies such as wind, solar, biomass, fuel cell
technology, tidal, geothermal, and methane waste. Customers in this class could elect to
remain on the current standard rate indefinitely, shift immediately to the new standby rate, or opt
for a five-year phase-in period beginning on the effective date of the new standby rates. Other
customers with preexisting onsite generation were offered two options: they could either shift
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immediately to the new standby rate or continue under the existing rate for four years and then
phase into the standby rate over the next four years.
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5.3. Interconnection Requirements
5.3.1. Overview
Interconnection requirements—the technical
and procedural requirements associated with
connecting a DG technology to the grid—
could inhibit investment in clean DG
technologies. Utility interconnection can be a
critical component of a successful DG project.
Connecting to the grid enables the facility to:
purchase power from the grid to supply
supplemental power as needed (e.g., during
periods of planned system maintenance); sell
excess power back to the grid; maintain grid
frequency and voltage stability; and ensure
utility worker safety. Standardized interconnection rules, which are generally developed and
administered by a state's public utility commission, establish clear and uniform processes and
technical requirements for connecting DG systems to the electric grid. Standardized
interconnection rules encourage the use of renewable resources and CHP by establishing
uniform processes and technical requirements that apply to all utility service territories within a
state. Standardized interconnection requirements reduce uncertainty, delays, and costs that
clean DG systems could encounter when obtaining approval for grid connection.
As of May 2007, 18 states have adopted standard interconnection rules for DG. An additional
14 states are in the process of developing their rules.
Resources: Interconnection Requirements
EPA information on interconnection standards:
http://www.epa.gov/chp/state-
policy/interconnection.html.
EPA Clean Energy-Environment Guide to Action.
http://www.epa.gov/cleanenergy/stateandlo
cal/guidetoaction.htm.
IREC information on interconnection standards:
http://www.irecusa.org/index.php?id=30.
5.3.2. Best Practices
Standardized interconnection rules are generally developed and administered by a public utility
commission. The policy objective is to establish clear, reasonable, and uniform requirements
for connecting DG systems to the electric grid. These uniform interconnection requirements
ensure that the costs of interconnection are the same throughout the state and are
commensurate with the nature, size, and scope of the DG project. Standard interconnection
rules can help reduce uncertainty and prevent excessive time delays and costs that DG systems
could encounter when obtaining approval for grid connection. They also help DG project
developers accurately predict the time and costs involved in the application process and the
technical requirements for interconnection. Finally, standard rules ensure that the project
interconnection meets the safety and reliability needs of both the energy end-user and the utility.
By developing standard interconnection requirements, states make progress toward leveling the
playing field for clean DG relative to centralized supply-side resources.
Successful interconnection standards address both the application process and technical
requirements for interconnecting DG projects of a specified type and size with the electric grid.
The application process for a well-designed interconnection rule will contain standard
application forms, timelines, fees, dispute resolution processes, insurance requirements, and
interconnection agreements. Another key element of interconnection rules is technical
interconnect requirements. Rules generally specify the type of generation technology that may
be interconnected, the required attributes of the electrical grids where the system will be
connected, the types of equipment and protocols required for the physical interconnection, and
the maximum system size that is eligible for the interconnection process. These requirements
typically specify that DG must conform to industry or national standards (such as IEEE 1547
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and UL 1741), and could include protection systems designed to minimize degradation of grid
reliability and performance as well as maintain worker and public safety.
Implementing successful interconnection standards requires collaboration between a variety of
interested stakeholders to develop clear, concise rules that are applicable and appropriate to all
potential DG technologies. The stakeholder process should include entities such as electric
utilities, state public utility commissions, developers of clean energy systems, third-party
technical organizations (e.g., the Institute of Electrical and Electronic Engineers (IEEE) and
Underwriters Laboratory, Inc. (UL)), RTOs, and other governmental stakeholders such as
environmental and public policy agencies.
Based on state experiences in developing standardized interconnection rules, the following best
practices can help other states develop similar policies:
• Develop standards that cover the scope of the desired DG technologies, generator
types, sizes, and distribution system types.
• Develop an application process that is streamlined with reasonable requirements and
fees. Consider making the process and related fees commensurate with generator size.
For example, develop a straightforward process for smaller or inverter-based systems
and more detailed procedures for larger systems or those using rotating devices (such
as synchronous or induction motors) to fully assess their potential impact on the
electrical system.
• Create a streamlined process for generators that are certified compliant to IEEE and UL
standards. UL Standard 1741 provides design standards for inverter-based systems
under 10 kW. IEEE Standard 1547 establishes design specifications and provides
technical and test specifications for systems rated up to 10 MW. These standards can
be used to certify electrical protection capability.
• Consider adopting portions of national models such as those developed by the National
Association of Regulatory Utility Commissioners (NARUC), MidAtlantic Distributed
Resources Initiative (MAORI), and FERC, and successful programs in other states such
as Maryland or Oregon. Consistency within a region increases the effectiveness of
these standards. Developing consistency among states is also important in reducing
compliance costs for the industry based on common practices.
• Try to maximize consistency between the RTO and the state standards for large
generators.
Once developed, best practices for implementation of standardized interconnection
requirements include:
• Working collaboratively to establish monitoring activities to evaluate the effectiveness of
interconnection standards and application processes.
• Periodically reviewing and updating standards based on monitoring activities, including
feedback from utilities and applicants.
• Working with groups such as IEEE to monitor industry activities and to stay up-to-date
on standards developed and enacted by these organizations.
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5.3.3. Best Practice Examples
• Texas Public Utility Commission: In November 1999, the Texas PUC adopted
substantive rules that apply to interconnecting generation facilities of 10 MWor less.
The rules require that Texas utilities evaluate applications based on pre-specified
screening criteria, including equipment size and the relative size of the DG system to
feeder load. These rules are intended to streamline the interconnection process for
applicants. Texas' interconnection standards are available at:
http://www.puc.state.tx.us/electric/business/dg/dgmanual.pdf.
• New York Public Service Commission: New York was one of the first states to issue
standardized statewide interconnection requirements for DG systems. Enacted in
December 1999, the initial requirements were limited to DG systems rated up to 300
kilowatts (kW) connected to radial distribution systems. In September 2005, New York
modified these interconnection requirements to include interconnection to radial and
secondary network distribution systems for DG with capacities up to 2 megawatts (MW).
New York's interconnection requirements are available at:
http://www.dps.state.ny.us/distgen.htm.
• Oregon Public Utility Commission: Oregon adopted the Standard Small Generator
Interconnection Rule for DG sources in July 2007. The rule applies to small DG units of
10 MWor less and outlines a four-tiered application fee schedule, depending on the
unit's generating capacity and if the unit plans to export power offsite. The rule also
includes a provision for expedited review for "field approved" interconnection equipment
in addition to "certified equipment." Oregon's proposed rule and accompanying
documents are available at: www.puc.state.or.us/PUC/admin rules/intercon.shtml.
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Resources: CHP
EPA CHP Partnership:
http://www.epa.gov/chp/.
CPUC SGIP Program:
http://www.cpuc.ca.gov/PUC/energy/sgip
Connecticut Demand-Side RFP 2006:
http://www.connecticut2006rfp.com/cont
ext.php.
ConEdison Demand-Side RFP 2007:
http://www.coned.com/sales/business/tar
getedRFP2007.asp.
5.4. Combined Heat and Power (CHP)
5.4.1. Overview
A CHP system is substantially more efficient than
purchasing electricity from the grid and meeting
thermal needs with a boiler or process heater.
Typical fuel use efficiencies for CHP systems
range between 60 percent and 75 percent.
Additional pollution prevention benefits are
achieved due to the elimination of energy
transmission and distribution losses as CHP
systems produce energy where it is used.
Incentive programs are one way to promote CHP
development. The California Self-Generation
Incentive Program (SGIP) is one example of a
successful program promoting CHP and other
forms of clean DG. Another strategy to increase
CHP capacity is to initiate a DG procurement process. In some areas, regional grid operators
such as ISO-New England have been working with FERC to implement locational capacity and
locational forward reserve markets as one mechanism to promote the development of required
new capacity on the electric grid. However, such markets could potentially expose ratepayers
to higher costs in part due to Federally Mandated Congestion Charges (FMCC) and other
charges. As an alternative, some states have launched procurement processes for DG
applications, including CHP, to meet capacity needs. The State of Connecticut and the New
York utility, Consolidated Edison (ConEd), have both initiated such procurement efforts using a
Request for Proposal (RFP) process. Both RFPs encourage the development of new DG by
establishing long-term contracts and other financial incentives.
5.4.2. Best Practices
Best practices for supporting the development of clean DG opportunities such as CHP include:
• Institute forums for collaboration between state agencies, utilities, and regional grid
operators to implement policies that encourage development of clean distributed energy
resources (including CHP) to meet grid capacity requirements.
• Develop long-term financial incentives and/or procurement contracts to decrease the
risks associated with investment in CHP and other clean DG applications, and support
market development by assuring project developers of a viable revenue stream.
• Ensure that state PUC commissioners and staff have current and accurate information
regarding the relevant rate issues and the potential benefits of clean DG in meeting grid
capacity requirements.
• Open a generic PUC docket to explore the potential of targeted clean energy solutions to
address grid congestion and utility-proposed grid upgrades and/or new power plants.
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5.4.3. Best Practice Examples
California
As of November 2007, California had over 1,100 MW of distributed CHP capacity (systems of
20 MW in capacity or less).57 The Distributed Generation and Cogeneration Policy Roadmap for
California released by the CEC in 2007 establishes an aggressive statewide goal of 3,300 MW
of CHP capacity by 2020.58
In addition to establishing a supportive regulatory framework for DG, (e.g. standardized
interconnection rules, net metering, and exemptions from standby charges), California has run a
statewide incentive program since 2001. Funding for the SGIP Program has been extended
through 2011, and the program provides incentives to customers who offset their purchased
electricity requirements with onsite microturbines, gas turbines, wind turbines, fuel cells, and
internal combustion (1C) engines. Statewide program funding for 2007 is approximately $75
million. The program is administered by PG&E, SCE, and Southern California Gas Company in
their service territories, and by the San Diego Regional Energy Office in San Diego Gas &
Electric Company's service territory. The CPUC provides program oversight.
SGIP targets businesses and large institutional customers. In order to receive incentives,
generation must be installed behind the customer meter and operate in parallel with the grid,
meaning that sources of backup power generation are not eligible for SGIP incentives. Systems
powered with fossil fuels must have an overall system efficiency of 60 percent and a NOx
emissions rate less than or equal to 0.07lbs/MWh. Eligible equipment must be less than 5 MW
in capacity, but there is no minimum capacity requirement.
Incentives are paid based on installed system capacity, and the program offers different
incentive tiers for DG applications that employ renewable versus non-renewable fuels. The
most recent impact evaluation of the SGIP program estimated that the program had a peak
demand impact of 55 MW in 2004, based on a total installed capacity of 100 MW. The unit
demand impact was estimated to be 0.39 kWpeak/kWinstaiied for solar PV systems5, 0.93 kWp/kW
for fuel cells, and 0.58 kWp/kWj for all other systems (1C engines, microturbines, and gas
turbines). The evaluation notes that the peak demand impact of systems in the 1C
engine/microturbine/gas turbine category was strongly influenced by the fact that 26 percent of
systems in this category were idle at the time of the 2004 CA ISO peak load.59
Connecticut
Connecticut's Public Act 05-01, An Act Concerning Energy Independence (EIA), authorized the
Connecticut Department of Public Utility Control (DPUC) to launch a competitive procurement
process focused on creating new supply-side and demand-side resources to reduce FMCCs.
The DPUC issued a RFP in September 2006 for development of the following resources: "(1)
customer-side distributed resources; (2) grid-side distributed resources; (3) new generation
facilities, including expanded or re-powered generation; and (4) contracts for a term of no more
than fifteen years between a person and an electric distribution company for the purchase of
electric capacity rights." The targeted timeframe for FMCC reduction from new projects is for the
period beginning May 1, 2006, and ending on December 31, 2010. Projects are evaluated
based on their contribution towards lowering Connecticut ratepayer costs.
As of 2007, PV systems are no longer included in the SGIP program as they are now covered by the California Solar Initiative
and the New Solar Homes Partnership (see Section 5.5.3).
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DPUC's broad eligibility criteria include new generation facilities, additional investments in
existing generation facilities that increase total grid capacity in Connecticut, conservation and
other demand-side resources, and energy efficiency projects. DG projects are considered
eligible to participate in this RFP. However, since DG has other opportunities under EIA,
projects can choose to participate in this process or can participate in other programs, but not
both.
The two local distribution companies, Connecticut Light and Power (CL&P) and United
Illuminating (Ul), will serve as the counterparty to contracts. Costs for the contracts entered into
under the procurement process will be allocated equally on a load ratio basis to CL&P and Ul
resulting in a consistent $/kWh charge. There are three possible contract options under the
RFP: one for generation, one for demand response, and one for other demand resources
(including energy efficiency).
New York
There are a variety of financial incentives available to reduce electricity demand in the ConEd
service territory, which is comprised of the five boroughs of New York City and a portion of
Westchester County. Incentives are provided through statewide programs administered by
NYSERDA and the Targeted Demand-Side Management Program (TP) administered by ConEd
in its service territory. ConEd has issued multiple RFPs for demand-side projects under the TP.
The most recent RFP was issued in August 2007 and calls for 158 MW of total demand
reduction through clean DG and energy efficiency projects.60
Each qualifying project must produce at least 500 kW of demand reduction, be located in one of
the geographic areas specified in the RFP, and deliver demand reductions according to the RFP
schedule. Clean DG projects must reduce an existing electric load and should not include
exports of power to the grid. Eligible DG technologies include natural gas-fired reciprocating
engines, microturbines, combustion gas turbines and fuel cells. Eligible energy efficiency
measures eligible for funding under the RFP include energy-efficient air conditioning, lighting,
refrigeration, motors, and steam chillers.
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5.5. Solar Energy
5.5.1. Overview
Solar energy—specifically solar electric power
generated with photovoltaic technology—is an
appealing renewable energy option for addressing
high electric demand given that the resource is
greatest when peak summer electric demand is
highest. In addition to lowering peak demand and
related emissions by offsetting grid-supplied
power, solar energy systems can reduce strains on
the electric transmission and distribution system.
Resources: Solar PV
New Jersey Clean Energy Program:
http://www.njcleanenerqy.com/renewabl
e-enerqy.
Go Solar California:
http://www.qosolarcalifornia.ca.qov/.
One of the greatest barriers to solar energy development is the high initial cost of installing a PV
system. Analysis by Lawrence Berkeley National Laboratory (LBNL) determined that in 2004-
2005, PV systems in California had an average installed cost of just under $9 per watt, declining
at an annual rate of around 7 percent per year.61 Other challenges include the complexity of the
technology and associated informational and transaction cost barriers from the customer's
perspective, and immature markets for solar system supply and installation. To address these
barriers, supportive policies at the local, state, and federal level are essential to promoting solar
energy development. Common forms of support include rebates based on the size of the
system, production-based incentives, tax incentives, and renewable portfolio standards
requiring the use of solar power to meet customer demand. Two states—New Jersey and
California—are national leaders in promoting PV development.
5.5.2. Best Practices
To offset the high cost of solar PV installations, incentives and financing mechanisms provide
essential support for solar energy development. To facilitate that development of a robust solar
market, incentives should remain relatively stable overtime, though incentives could be
gradually reduced over time as the solar market becomes more robust and costs decline.
Historically, solar rebates have been based on the rated system capacity (kW). However,
incentives based on energy production (kWh) represent an emerging policy best practice.
Production-based incentives are designed to promote optimal system performance as some
studies have shown installed systems producing less electricity than expected. Typical
problems resulting in poor performance include equipment shading, component failure, poor
installation practices, and deviations from manufacturer specifications.62 In addition, production-
based incentives provide a revenue stream to offset ongoing system financing costs (e.g., loan
and interest payments).
Consumer education and technical assistance are also important elements of programs that
support solar energy development. Some programs train and certify networks of solar installers
to ensure quality installations that maximize production. Consumer education and outreach is
important to overcome informational barriers and risk perceptions.
5.5.3. Best Practice Examples
New Jersey
New Jersey's solar program is widely praised by the solar industry and renewable energy
advocates. In addition to establishing an aggressive Renewable Portfolio Standard (RPS) in
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April 2006 where 22.5 percent of the state's electric sales must come from renewable sources
by 2021, the New Jersey Board of Public Utilities (NJBPU) has established a solar set-aside
requiring that 2 percent of the RPS be met with solar electric power. At current electric
consumption levels, New Jersey's solar set-aside is forecast to require 1,800 MW of solar
capacity by 2021, making it the nation's largest solar commitment relative to population and
electricity consumption.63
To achieve the state's aggressive solar goals, the New Jersey Office of Clean Energy (OCE)
operates three integrated programs that encourage residents, building owners, and others to
install solar technology:
• Customer On-Site Renewable Energy (CORE) Program: Under CORE, consumer
rebates are available to residential and business customers to help reduce the up-front
cost of PV systems. Rebates are based on system size (kW).
• Solar Renewable Energy Rebates (SRECs): The New Jersey SREC Program provides
an additional mechanism for financing for clean, emissions-free solar electricity. The
SREC program is an emerging market-based financing option for solar PV that offers a
production-based revenue stream. Owners of solar arrays obtain an SREC each time
they generate 1 MWh. The credits can then be sold to provide a revenue stream to
offset ongoing financing costs. Recently the SREC program is compensating system
owners at an average rate of $0.20 per kWh. The program is capitalized by funds
generated from utility Alternative Compliance Payments (ACP), and the estimated
impact on utility ratepayers is around $0.00002 per kWh.64
• Clean Energy Financing Program: Offers low-interest loans and grants to customers
and is designed to help businesses, schools, and municipalities finance solar
installations and other clean energy opportunities.
New Jersey is the fastest growing solar market in the country. In 2005, solar capacity increased
by 157 percent. The state credits this rapid growth to the combination of rebates, financial
incentives, and technical support offered by the OCE. New Jersey officials say that the
programs have been so successful that the state has had problems meeting demand.
Currently, in order to meet New Jersey's aggressive solar requirements more efficiently, the
state is transitioning from up-front CORE rebates to an SREC-based financing program. In
2007 the OCE launched an SREC-only pilot program whereby customers can participate in the
SREC market without participating in the CORE rebate program.
Since the inception of the state's solar incentive programs in 2001, over 2,300 New Jersey
residential, commercial, public, and non-profit entities have installed solar electric systems. In
total, CORE has paid out over $170 million in incentives, resulting in over 40 MW of program-
induced solar capacity.65 A joint state-federal analysis estimates that CORE reduced NOx
emissions by 1.1 tons during the 2005 ozone season.
California
California's RPS was established in 2002, with the goal of meeting 20 percent of the state's
electricity demand with renewable energy by 2017. As part of Governor Schwarzenegger's
Million Solar Roofs Program, California has the goal of adding 3,000 MWof solar electric
capacity by 2017, with total state funding of $3.3 billion. Solar incentive programs in California
are administered by the California Energy Commission (CEC) and the California Public Utility
Commission (CPUC).
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• California Solar Initiative (CSI): Administered by the CPUC, CSI provides consumer
incentives for solar installations. As of 2007, the program is transitioning from capacity-
based (kW) to performance-based (kWh) incentives, offering different incentive tiers for
residential, commercial, and nonprofit customers. Currently, all solar energy systems of
100 kWor larger receive monthly incentive payments based on actual energy production
for a period of five years. Systems smaller than 100 kW receive an up-front incentive
payment based on expected system performance, which is calculated based on
equipment ratings and installation factors such as geographic location, tilt, and shading.
Though smaller systems can opt in to performance-based incentives now, beginning in
2010 all systems larger than 30 kWwill receive incentive payments based on actual
energy production. Another key feature of the CSI is that incentive levels are
automatically reduced over time based on the aggregate capacity of solar installations.'
• New Solar Homes Partnership (NSHP): CEC administers this 10-year, $400 million
program to encourage the integration of solar technologies in new home construction.
By 2017, the program has the goal of achieving 400 MWof installed solar electric
capacity on new homes, with PV systems installed on 50 percent of all new homes built
in California. The NSHP targets the single family, low income, and multifamily housing
markets, and offers incentives to developers and builders for solar-integrated new
construction projects. Incentives are based on expected system performance and
homes must be at least 15 percent more energy-efficient than Title 24 building standards
to qualify for incentives. As with the CSI program, incentive levels automatically decline
based on the aggregate capacity of solar installations.
California solar incentive tiers are available at: http://www.qosolarcalifornia.ca.qov/csi/performance based.html.
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Endnotes
Ozone Transport Commission (March 2007). Memorandum of Understanding Among the States
of the Ozone Transport Commission Concerning the Incorporation of High Electrical Demand Day
Emission Reduction Strategies into Ozone Attainment State Implementation Planning. Available
at: http://www.otcair.org/document.asp?fview=meetinq#.
2 York, Kushler, Witte (February 2007). Examining the Peak Demand Impacts of Energy Efficiency:
A Review of Program Experiences and Industry Practices. ACEEE.
3 York, Kushler, Witte (February 2007). Examining the Peak Demand Impacts of Energy Efficiency:
A Review of Program Experiences and Industry Practices. ACEEE.
4 York, Kushler, Witte (February 2007). Examining the Peak Demand Impacts of Energy Efficiency:
A Review of Program Experiences and Industry Practices. ACEEE.
5 York, Kushler, Witte (February 2007). Examining the Peak Demand Impacts of Energy Efficiency:
A Review of Program Experiences and Industry Practices. ACEEE.
6 York, Kushler, Witte (February 2007). Examining the Peak Demand Impacts of Energy Efficiency:
A Review of Program Experiences and Industry Practices. ACEEE.
7 York, Kushler, Witte (February 2007). Examining the Peak Demand Impacts of Energy Efficiency:
A Review of Program Experiences and Industry Practices. ACEEE.
8 2005 Buildings Energy Data Book, DOE/EERE
9 New York State Energy Research and Development Authority (May 2006). New York Energy
$martSM Program Evaluation and Status Report, 5-39-41.
10 Quantec, LLC, and Summit Blue Consulting, LLC, on behalf of NYSERDA (May 2006). New York
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11 State of Wisconsin, Public Service Commission of Wisconsin. (September 2007). Focus on
Energy Evaluation, Semiannual Report (FY07, Year End). Available at:
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fidf-
12 U.S. Department of Energy, Energy Information Administration (2001). Residential Energy
Consumption Survey.
13 Consortium for Energy Efficiency (2007). Fact Sheet: Residential Central Air Conditioning and
Heat Pumps. Available at: http://www.cee1.org/resrc/facts/rs-ac-fx.pdf.
14 New Jersey Board of Public Utilities, Office of Clean Energy. New Jersey's Clean Energy
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15 Summit Blue (September 2006), Independent Audit of Texas Energy Efficiency Programs in 2003
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16 U.S. Department of Energy: Energy Efficiency and Renewable Energy. Emerging Technologies:
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U.S. Environmental Protection Agency September 2008
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Endnotes
17 eSource (2006). Refrigerator Recycling Programs: Rounding up the Old Dogs for Easy Energy
Savings.
18 Nexus Market Research, Inc. (December 2005). Impact, Process, and Market Study of the
Connecticut Appliance Retirement Program: Overall Report. Prepared by Nexus Market
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Plans.
CDS Associates Inc. (January 2007). Vermont Electric Energy Efficiency Potential Study.
Prepared for the Vermont Department of Public Service.
19 eSource (2006). Refrigerator Recycling Programs: Rounding up the Old Dogs for Easy Energy
Savings.
CL&P am
06-10-02.
20 CL&P and Ul (October 2006). Conservation and Load Management Plan 2007 and 2008. Docket
21 eSource (2006). Refrigerator Recycling Programs: Rounding up the Old Dogs for Easy Energy
Savings.
22 KEMA-XENERGY (February 2004). Measurement and Evaluation Study of 2002 Statewide
Residential Appliance Recycling Program. Prepared by KEMA-XENERGY for Southern California
Edison.
23 U.S. Department of Energy, Energy Information Administration (June 2007). Annual Energy
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24 U.S. Department of Energy, Energy Information Administration. Preliminary End-Use
Consumption Estimates by Principal Building Activity Based on 1999 Commercial Buildings
Energy Consumption Survey. Available at:
http://www.eia.doe.gov/emeu/cbecs/enduse consumption/intro.html
25 U.S. Department of Energy, Energy Information Administration. Preliminary End-Use
Consumption Estimates by Principal Building Activity Based on 1999 Commercial Buildings
Energy Consumption Survey. Available at:
http://www.eia.doe.gov/emeu/cbecs/enduse consumption/intro.html.
26 Quantum Consulting (2004). National Energy Efficiency Best Practices Study, Volume NR1 -
Nonresidential Lighting Best Practices Report. Estimates of participant impacts based on small
commercial program data from Xcel Energy, KEMA-Xenergy BEST, SDG&E, SMUD, and CL&P,
and large commercial program data from Xcel Energy and the California lOUs.
Additional data for large commercial lighting programs was obtained for Nevada Power and We
Energies.
27 Quantum Consulting (2004). National Energy Efficiency Best Practices Study, Volume NR2 -
Nonresidential HVAC Best Practices Report. Estimates of participant impacts based on small
commercial program data from the New England Energy Efficiency Partnership and Glendale
Water & Power, and large commercial program data from the Los Angeles Department of Water
& Power.
U.S. Environmental Protection Agency September 2008
-------
Endnotes
28 PWP Inc. (June 2006). Final Evaluation, Monitoring, and Verification (EM&V) Report for the
EnergySmart Grocer Program 2004-2005. Prepared by PWP Inc. for the Energy Division,
California Public Utilities Commission. Available at: www.calmac.org.
29 Quantum Consulting (2004). National Energy Efficiency Best Practices Study, Volume NR1 -
Nonresidential Lighting Best Practices Report. Estimates based on data from Xcel Energy,
California lOUs, and the Sacramento Municipal Utility District.
30 Quantum Consulting (2004). National Energy Efficiency Best Practices Study, Volume NR2 -
Nonresidential HVAC Best Practices Report. Estimates based on data from the Los Angeles
Department of Water & Power and the New England Energy Efficiency Partnership.
31 Xcel Energy (April 2007). 2006 Status Report & Associated Compliance Filings: Minnesota
Natural Gas and Electric Conservation Improvement Program.
32 Quantum Consulting (2004). National Energy Efficiency Best Practices Study, Volume NR2 -
Nonresidential HVAC Best Practices Report.
33 PWP Inc. (June 2006). Final Evaluation, Monitoring, and Verification (EM&V) Report for the
EnergySmart Grocer Program 2004-2005. Prepared by PWP Inc. for the Energy Division,
California Public Utilities Commission. Available at: www.calmac.org.
34 Quantum Consulting (2004). National Energy Efficiency Best Practices Study, Volume NR5 -
Nonresidential Large Comprehensive Incentive Programs Best Practices Report. Estimates of
participant impacts based on data from the California lOUs, NYSERDA, Xcel Energy, National
Grid, and WP&L.
35 Estimates based on data from the following sources:
CenterPoint Energy 2004 RCx pilot data from: Summit Blue (September 2006), Independent
Audit of Texas Energy Efficiency Programs in 2003 and 2004.
CL&P O&M Services program, RCx pilot in 2006 from: CL&P and Ul (October 2006),
Conservation and Load Management Plan 2007-2008.
SDG&E RCx pilot in 2004-2005 data from: Itron (February 2007), PECI San Diego
Retrocommissioning Program EM&V: SDG&E Service Area. CPUC Evaluation ID 1381-4.
Prepared for Portland Energy Conservation, Inc. Available at:
http://www.calmac.org/publications/PECI RCxProgram FinalReport.pdf.
Xcel Energy, 2006 Building Recommissioning Program data from: Xcel Energy (April 2007), 2006
Status Report & Associated Compliance Filings. Minnesota Natural Gas and Electric
Conservation Improvement Program.
36 Quantum Consulting (2004). National Energy Efficiency Best Practices Study, Volume NR5 -
Nonresidential Large Comprehensive Incentive Programs Best Practices Report. Estimates
based on data from the California lOUs, NYSERDA, Northeast Utilities, National Grid, and
Efficiency Vermont.
37 Austin Energy (October 2005). Austin Energy's Cool Roof Rebate Program. Presentation by
Norman Muraya at the Heat Island Teleconference. Available at:
http://www.epa.gov/hiri/resources/pdf/Heatlsland-ReflectiveRoofOct27 2005%20.pdf.
38 ACEEE (April 2003). America's Best: Profiles of America's Leading Energy Efficiency Programs,
SMUD Cool Roof Program Profile. Available at: http://aceee.org/utility/12fsmudcoolroof.pdf.
U.S. Environmental Protection Agency September 2008
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Endnotes
39 Federal Energy Regulatory Commission (August 2006). Assessment of Demand Response and
Advanced Metering. Docket No. AD-06-2-000.
40 Federal Energy Regulatory Commission (August 2006). Assessment of Demand Response and
Advanced Metering. Docket No. AD-06-2-000.
41 Federal Energy Regulatory Commission (August 2006). Assessment of Demand Response and
Advanced Metering. Docket No. AD-06-2-000.
42 RLW Analytics and Neenan Associates (December 2005). An Evaluation of the Performance of
the Demand Response Programs Implemented by ISO-NE in 2005.
43 Federal Energy Regulatory Commission (August 2006). Assessment of Demand Response and
Advanced Metering. Docket No. AD-06-2-000.
44 Quantum Consulting (April 2006). Evaluation of 2005 Statewide Large Nonresidential Day Ahead
and Reliability Demand Response Programs. Available at:
http://www.calmac.org/publications/2006-04-28 WG2 2005 FINAL REPORT.pdf.
45 Federal Energy Regulatory Commission (August 2006). Assessment of Demand Response and
Advanced Metering. Docket No. AD-06-2-000.
46 Nevada Power Company (June 2006). Project Data Sheet: Air Conditioner Load Management.
Completed as part of the 2006 Integrated Resource Plan (IRP) filing.
47 Federal Energy Regulatory Commission (August 2006). Assessment of Demand Response and
Advanced Metering. Docket No. AD-06-2-000.
48 Federal Energy Regulatory Commission (August 2006). Assessment of Demand Response and
Advanced Metering. Docket No. AD-06-2-000.
49 Federal Energy Regulatory Commission (August 2006). Assessment of Demand Response and
Advanced Metering. Docket No. AD-06-2-000.
50 Federal Energy Regulatory Commission (August 2006). Assessment of Demand Response and
Advanced Metering. Docket No. AD-06-2-000.
51 Federal Energy Regulatory Commission (August 2006). Assessment of Demand Response and
Advanced Metering. Docket No. AD-06-2-000.
52 Federal Energy Regulatory Commission (August 2006). Assessment of Demand Response and
Advanced Metering. Docket No. AD-06-2-000.
53 Charles River Associates (March 2005). Impact Evaluation of the California Statewide Pricing
Pilot: Final Report.
54 Charles Goldman, et al. (August 2004). Does Real-time Pricing Deliver Demand Response? A
Case Study of Niagara Mohawk's Large Customer RTF Tariff, Lawrence Berkeley National
Laboratory: LBNL-54974.
55 California Energy Commission (March 2007). Distributed Generation and Cogeneration Policy
Roadmap for California. Available at: http://www.energv.ca.gov/2007publications/CEC-500-2007-
021/CEC-500-2007-021 .PDF
56 State of New York Public Service Commission (July 2003). Press Release: "PSC Votes to
Approve New Rates for Standby Electric Service - Commission Balances Benefits of Efficient
U.S. Environmental Protection Agency September 2008
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Endnotes
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57 Energy and Environmental Analysis. Combined Heat and Power Installation Database. Available
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59 Itron, Inc. (April 2005). CPUC Self-Generation Incentive Program Fourth-Year Impact Report.
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60 Consolidated Edison Company of New York (August 2007). Request for Proposals to Provide
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61 Ernest Orlando Lawrence Berkeley National Laboratory (January 2006). Letting the Sun Shine on
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62 Ernest Orlando Lawrence Berkeley National Laboratory and the Clean Energy States Alliance
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63 New Jersey Board of Public Utilities, Office of Clean Energy (August 2007). New Jersey
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64 Database of State Incentives for Renewables & Efficiency (DSIRE), NJ Board of Public Utilities -
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65 New Jersey Clean Energy Program, CORE Activity. Web site accessed October 24, 2007,
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U.S. Environmental Protection Agency September 2008
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