i CHP
SERA COMBINED HEAT AND
POWER PARTNERSHIP
Draft-
Portfolio Standards and the
Promotion of Combined Heat and Power
Energy Portfolio Standards
Energy portfolio standards (EPS) are becoming
a widely applied method of encouraging the
development of renewable and efficient energy
resources. The most commonly implemented
portfolio standards are renewable portfolio
standards (RPS), although there is increasing
discussion about Energy Efficiency Resource
Standards (EERS). An RPS requires electric
utilities and other retail electric providers to
supply a specified minimum amount of
customer load with electricity from eligible
renewable energy sources. This amount
usually begins as a small percentage of the
total electricity load that increases gradually
over time (e.g., 5 percent by 2010, increasing
1 percent per year to 15 percent by 2020).
Through January 2008, EPS requirements or
goals have been established in 29 states plus
the District of Columbia (see Figure I).1 Most
EPSs have been established within the last five
years, with 10 states enacting RPS
policies in 2004 and 2005 alone.2
combined heat and power (CHP), and are
including these technologies in expanded or
alternative EPS policies. For example, some
states, like Connecticut, are promoting a
variety of energy efficient technologies in their
EPS policies through a system of different
technology classes or tiers; each tier requires
a specific percentage or amount (in
megawatts) of energy production to come
from specified renewable or efficient
technologies. Connecticut and Pennsylvania
have both included energy efficiency and CHP
in a separate tier in their EPSs.
Eight statesColorado, Connecticut, Hawaii,
Nevada, North Carolina, North Dakota,
Pennsylvania, and Washingtoninclude CHP
and/or waste heat recovery as an eligible
resource and Arizona explicitly includes
renewably fueled CHP systems. CHP, also
known as cogeneration, is the simultaneous
production of electricity and heat from a
The type of resources that are
eligible under an RPS or EPS varies
by state. Most states include
renewable resources such as solar,
wind, small hydropower and
ocean/tidal/thermal systems,
biomass, and landfill gas. Some
states also include advanced
technologies, such as fuel cells,
that possess beneficial energy and
environmental attributes. In
addition, states are increasingly
recognizing the energy,
environmental, and economic
benefits of energy efficiency and
Figure 1 - States With RPS Requirements
States with RPS goals
Source: Database of State Incentives for Renewable Energy (DSIRE) last
accessed January 2008, www.dsireusa.org.
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single fuel source such as natural gas or biomass/biogas.
CHP systems offer considerable environmental benefits
when compared to traditionally purchased electricity and
onsite-generated thermal energy.
Combined Heat and Power (CHP)
By capturing and utilizing heat that is normally wasted,
CHP systems typically achieve total system efficiencies of
60 to 80 percentcompared to less than 50 percent for
equivalent separate heat and power systems. With this
increased efficiency, a CHP system uses 35 percent less
fuel to achieve the same energy output as separate heat
and power systems.
Because CHP is a form of distributed generation (DG) in
which less fuel is combusted, it offers a number of
environmental and economic benefits:
Reduced emissions of all air pollutants
- Fewer greenhouse gas emissions, such as carbon
dioxide (C02)
- Fewer criteria air pollutants, including nitrogen oxides
(NOX) and sulfur dioxide (S02)
Reduced grid congestion and avoided distribution losses
Increased reliability and power quality
Lower operating costs
For more specific information about how CHP works and
what its benefits are, see the addendum at the end of this
paper or visit EPA's CHP Partnership Web site at
www.epa.gov/chp.
RPS Design and Implementation
States have recognized the increasing need to encourage
efficient and nonpolluting sources of energy. RPSs are the
favored approach for most states because they can
stimulate market and technology development using a
cost-effective, market-based approach that is also
administratively efficient.
Most RPS requirements work through the application of a
trading program either in the state or on a regional basis.
Qualifying renewable resources receive a certain number
of certificates per year, usually based upon their
generation (e.g., 1 megawatt-hour [MWh] = 1 certificate).
These certificates are most often referred to as renewable
energy certificates (RECs). Renewable energy generators
can then sell RECs to electricity suppliers, such as large
utilities, that must also fulfill the RPS. RECs not only
generate revenue for renewable generators, but they are
also the measure of compliance for the RPS policy. REC
trading programs provide flexibility and reduce
administrative program costs in several ways:
Not every electricity supplier needs to develop and
operate renewable generation assets to comply.
Independent renewable developers have access to the
market.
Renewable energy can be supplied from the most
advantageous sites to electricity suppliers throughout a
state or a region.
RPSs often contain an alternative compliance mechanism
under which an electric supplier or distributor can pay a
fee to the state if they are unable to procure a sufficient
supply of RECs. The Alternative Compliance Payment
(ACP) is often set at a high level to encourage the
development of renewable projects. Payments to an ACP
fund are usually used by the state to promote the
development of renewable projects. For example, in
Massachusetts, the ACP goes to the Massachusetts
Technology Collaborative. This organization then uses the
money to fund clean energy and green buildings and
infrastructure programs. The clean energy program's goal
is to support community and utility projects that use
wind, solar, and bioenergy and to educate citizens about
green electricity markets. The green buildings and
infrastructure program provides funding to renewable
energy technologies in all types of buildings. In
Connecticut, the ACP goes to the Connecticut Clean
Energy Fund to promote Class I and Class II resources
(new renewable generation) and to the conservation and
load management program to support Class III resources
(energy efficiency and CHP).
Elements of a Successful RPS Policy
There are several key components to the design and
implementation of an RPS, discussed below.
Eligibility
The definition of which technologies are eligible for
inclusion is quite varied. Table 1 summarizes the
technology eligibility for state RPS programs as of January
2008. While states identify renewable technologies
differently, most tend to include, at a minimum, solar,
wind, biomass, and landfill gas/biogas. Some programs
only allow combustion technologies that use biomass or
other renewable fuels; others allow the use of any fuel as
long as it is in an approved technology. In the case of
CHP, inclusion may require meeting a minimum efficiency
percentage (e.g., 50 percent total efficiency in
Connecticut) or designation as a "qualifying facility" under
the Public Utilities Regulatory Policy Act. These efficiency
minimums also usually require some threshold of
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Table 1 - Summary of State
Energy Portfolio Standards
Energy Source
AZ
CA
CO
CT
DE
DC
HI
IA
IL
MA
MD
ME
MN
MO*
MT
NC
ND*
NH
NT
NM
NV
NY
OR
PA
RI
TX
VT*
WA
WI
Biofuels
Biomass
0
0
CHP/Waste Heat
0*
0
Energy Efficiency
Fuel Cells*
0
0**
1
CU
1
o
O
iH
X
Landfill Gas
Municipal Waste
Ocean Thermal
Photovoltaics
Solar Themal Electric
3
Waste Tire
1
a
e
s
recovered electric and/or thermal energy, such as
Connecticut's 20 percent minimum thermal threshold. The
RPS eligibility requirements might also set emission limits
for emitting technologies. For example, through 2005,
California sources were required to produce zero emissions
or meet the 2007 state emission limits for DG to qualify as
eligible. In Connecticut, specific emission limits apply to
biomass facilities.
CHP systems that are fueled with a qualifying renewable
resource, such as biomass, are eligible under RPSs. In this
context, typically only the electric output of the CHP system
is eligible. States can also include the thermal output for
these systems in their RPS to fully value the benefits of CHP.
There are numerous states that credit thermal output in
their environmental regulations. For example, California,
Maine, Rhode Island, and Texas include thermal output in
their Small DG Rule.3 So do EPA's Combustion Turbine New
Source Performance Standards.4 To account for the thermal
output of CHP units, these states convert the measured
steam output (British thermal unit, or Btu) to an equivalent
electrical output (MWh). This is done through a unit
conversion factor (1 MWh = 3.413 MMBtu). By adding the
thermal and electric output together, states are recognizing
the full environmental and emissions benefits of CHP. RPS
language can be modified to state that CHP output will be
calculated as the electric output plus the thermal output in
MW, based on the conversion of 1 MWh = 3.413 MMBtu of
heat output.
RPSs often include several tiers or classes of generators in
order to differentiate between different technologies and
allow different targets to be set for different classes.
Often, Tier I includes primarily zero-emitting renewables,
while other tiers include biomass or other emitting
renewable technologies or advanced low-emitting non-
renewables. Some states, such as Connecticut and
Pennsylvania, can utilize a separate tier for energy
efficiency and CHP, ensuring these resources do not
compete with renewable energy technologies. Different
generation targets are then set for each tier according to
state goals, resources, and interests. RECs for different
tiers typically garner different prices, with the zero-
emitting renewables typically having the highest prices
(see Table 2). For example in New Jersey, the price for a
solar REC for the 2006-2007 calendar years was $240.
Consistency among state portfolio standards in a region
provides large benefits to the electric market. Considering
state and regional resource availability is central to the
success of a portfolio standard.
States with RPS goals not mandatory requirements.
'Renewable CHP systems are eligible; fossil-fueled CHP systems are not eligible.
**After January 1, 2010, hydrogen must be generated by renewable energy sources.
^Includes only those states that allow fuel cells using nonrenewable energy sources of hydrogen. Some states allow only renewable fuel cells (Arizona, California,
Colorado, Delaware, Massachusetts, Maryland, Missouri, New Mexico, New York, Rhode Island, Wisconsin) as eligible technologies.
Source: Database of State Incentives for Renewable Energy (DSIRE) last accessed January 2008, www.dsireusa.org.
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Size of Requirement
The basis of the renewable requirement can vary but is
typically a percentage of annual generation or sales of
electricity. The size of the requirement is also quite
varied. Requirements normally start from a small
percentage and then grow by some increment each year
to achieve a plateau level by a specific target year,
subject to review. Table 3 shows the range of target
values in states with an RPS.
The size of both the initial and target values also depends
on which technologies and vintages are allowed in the
program. For example, Maine's first RPS required 30
percent clean energy, but it included many existing
biomass facilities, which already comprised more than 30
percent of the state's generation. It is also important for
states to conduct renewable energy, energy efficiency, and
CHP potential studies as a portfolio standard is created.
These studies ensure that the standard can be met
without placing too much strain on the affected utilities.
Alternative Compliance Payment
Many RPS programs include an Alternative Compliance
Payment (ACP) provision. The ACP sets a limit on the price
of RECs in case renewable generation does not keep up
with the requirements. If the regulated entities cannot
purchase RECs at a price below the ACP, they are allowed
to pay the state the ACP price as an alternative. The state
then uses the ACP funds to promote renewable projects.
The ACP price usually escalates over time. This structure
prevents the REC price from being too high while at the
same time provides funding for renewable development
when supply is scarce.
Vintage
Because the goal of an RPS is to encourage new sources of
renewable or efficient generation, many RPS requirements
state that eligible resources are those constructed after a
certain date, such as after or shortly before the rule is
promulgated. Some states credit incremental generation
added after the required vintage date; CHP systems in
Connecticut and biomass facilities in Massachusetts are
allowed such flexibility. In a few cases, existing facilities are
allowed full credit under the RPS (e.g., renewable facilities
under Maine's first RPS). As previously noted, the decision
on vintage also affects the appropriate size of the target.
Point of Origin
RPS programs are typically state programs that allow only
the use of RECs generated in that state. However, some
programs do allow trading of RECs from other states with
harmonious RPS programs that are in the same or an
adjacent power pool. The Northeast includes multiple
states in this category. However, some mechanism must
still ensure that RECs from other states meet appropriate
Table 2 - REC Prices in July 2007
(1 REC = 1 MW)
Connecticut
Class I
2007
$52.00
Class II
2007
$0.55
Maine
2007
$0.20
Massachusetts
2007
$54.50
Texas
2006
2007
2008
$2.75
$3.30
$3.40
Delaware
2007
$1.75
Rhode Island
2007
$48.00
New Jersey
Solar
2006/2007
$240.00
Class I
2006/2007
$40.00
Class II
2006/2007
2007/2008
$1.25
$1.35
Maryland
Tier I
2006
2007
$0.55
$0.95
Tier II
2006
2007
$0.60
$0.55
DC
Tier I
2007
$1.75
Tier II
2007
$0.75
Pennsylvania
Tier I
2007
$5.50
Source: Evolution Markets. July 2007 Monthly Market Update (2007)
www.evomarkets.com.
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eligibility criteria. If both states are in the same power
pool with a consistent attribute tracking system, ensuring
eligibility across state lines is easier. For example, states in
the New England Power Pool (NEPOOL) can rely on the
power pool's Generation Information System (CIS) to track
and compare RECs.
Table 3 - State Portfolio Targets
State
AZ
CA
CO
CT
DC
DE
HI
IA
IL
MA
MD
ME
MN
MO*
MT
ND*
NH
NC
NJ
NM
NV
NY
OR
PA
RI
TX
VA*
VT*
WA
WI
Target
(% of electric sales)
15% by 2025
20% by 2010
Investor-owned utilities (lOUs) 20%
by 2020; electric cooperatives and
municipal utilities 10% by 2020
27% by 2020
11% by 2022
20% by 2019
20% by 2020
105 MW
25% by 2025
4% by 2009 ( +l%/year after)
9.5% by 2022
10% by 2017
Xcel Energy (utility) 30% by 2020;
other utilities 25% by 2025
11% by 2020
15% by 2015
10% by 2015
23.8% by 2025 (16.3% new)
lOUs 12.5% by 2021; electric
cooperatives 10% by 2018
22.5% by 2021
lOUs 20% by 2020; rural electric
cooperatives 10% by 2020
20% by 2015
24% by 2013
Large utilities (>3% state's total
electricity sales) 25% by 2025
18% by May 31, 2021 (8% renewable
energy)
16% by 2020
5,880 MW by 2015
12% of 20007 sales by 2022
Total incremental energy growth
between 2005 and 2012 to be met with
new renewables (10% cap)
15% by 2020
10% by December 31, 2015
Specific Provisions
(% of electric sales)
4.5% by 2012 from distributed
energy resources
lOUs: 4.0% solar by 2020
4% energy efficiency and CHP
by 2010
0.386% solar by 2022
2.005% solar by 2019
18.75% wind by 2013
2% solar by 2022
Xcel Energy: 25% wind
0.3% solar by 2025
Energy efficiency measures up
to 3.13%; 5% after 2021
2.12% solar by 2021
Wind, solar: 0.02% each;
biomass, geothermal; 0.01%
each by 2011 (lOUs only)
1% solar by 2013
0.154% customer-sited by 2013
Smaller utilities 5-10% by 2025
(depending on size)
0.5% solar by May 31, 2021
States with RPS goals not mandatory requirements.
Source: Database of State Incentives for Renewable Energy (DSIRE) last accessed
January 2008, www.dsireusa.org.
Monitoring
In most cases, the formation of a REC is based on the
amount of electricity generated. Therefore, a program
must have a system of tracking the generation to ensure
that it comes from a qualifying resource. Many states
already have such tracking systems to meet emissions
disclosure requirements. NEPOOL's CIS tracks generation
and even classifies RECs according to their eligibility to
meet different state RPS requirements. The PJM
Generation Attributes Tracking System (GATS) can be used
to track generation attributes in the Mid-Atlantic region
and can form the basis for awarding RECs, as it is in
Pennsylvania. In California and other western states, the
Western Renewable Energy Generation Information
System (WREGIS) was created to issue, register, and track
RECs; the system helps monitor and track renewable
energy generation for both regulatory compliance and
voluntary market programs. The WREGIS covers the
Western Electricity Coordinating Council (WECC) service
area, which extends from Canada to New Mexico and
includes 14 western states and part of Baja California.
The Midwest Renewable Energy Tracking System (M-RETS)
tracks renewable energy generation in the form of RECs
for participating states (currently Illinois, Iowa, Minnesota,
Montana, North Dakota, South Dakota, and Wisconsin)
and assists in verifying compliance with individual state
RPS requirements or goals. M-RETS production data is
provided by the Midwest Independent Transmission
System Operator (MISO).
In Texas, the Electric Reliability Council of Texas (ERCOT)
allocates RECs to renewable generators each year for
every MWh metered on the grid. ERCOT then uses a pro-
rata basis to determine renewable requirements for each
retail electricity provider (REP). The requirements are
based on total electricity sales for a given year, not on
generation. REPs are required to retire RECs; they do not
have to buy the associated generation.
Trading
In most RPS states, affected entities must meet the RPS
through the surrender and retirement of RECs. The
affected entity can generate, purchase, or trade the RECs.
States typically utilize a regional tracking system that
allows renewable generators located anywhere within the
region to participate in the market. RECs are the currency
used to represent renewable generation that is creditable
against the RPS requirements for a seller or generator of
electricity. The affected entity can create the RECs itself or
purchase them from another eligible generator.
Trading RECs increases flexibility and reduces the cost of
compliance. This method provides a market that encourages
the development of eligible resources by many independent
developers by providing an important income stream for
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project developers. This income can be an important
component of the pro-forma financial package needed to
attract capital to finance a new project.
Trading allows the flexibility to develop renewable resources
wherever the available resource is most favorable, either
within the state or between states, allowing the
development of the most cost-effective resources. However,
accepting out-of-state RECs might reduce the amount of in-
state environmental improvement and economic
development resulting from the RPS. This tradeoff must be
evaluated against cost and resource availability to determine
the appropriate structure for any given state.
One state that deviates from the common RPS compliance
options is New York. New York's RPS works though a
method called a central procurement model. Under this
model, electric utilities collect a surcharge on electricity
sold to consumers. These funds are turned over to the
New York State Energy Research and Development
Authority (NYSERDA), which purchases RECs on behalf of
all the regulated entities.
State Examples of EPS That Include CHP
The inherent flexibility in RPS design allows states to identify
and promote specific resources or technologies that support
their environmental, energy, and economic development
goals. CHP is one of the technologies that supports each of
these goals. Table 1 summarizes the characteristics of
current state portfolio standards, including the nine states
that include CHP.5 Of these states, six include clean fossil-
fueled CHP, three include waste heat CHP, and one includes
renewably fueled CHP.6 State EPS programs that include CHP
are summarized below.
Connecticut
The Connecticut RPS was originally promulgated in 1998
and was revised in 2005 and 2007. In 2005, Connecticut
added a third tier to the RPS resource requirements,
establishing a new RPS Class III that must be fulfilled with
CHP, demand response, and electricity savings from
conservation and load management (C&LM) programs.7 In
2007, the Class III standard was expanded to include
systems that recover waste heat.8 The RPS standard
requires electric suppliers and distribution companies to
obtain 1 percent of their generation from Class III
resources beginning in 2007, increasing by 1 percent per
year until leveling out at 4 percent in 2010 and thereafter.
The total RPS requirement is 10 percent in 2008 and will
rise to 27 percent in 2020 (including Class I, Class II, and
Class III resources).
The Connecticut Department of Public Utility Control
(DPUC) released its final decision regarding the
implementation of a Class III standard on June 28, 2006,
in Docket No. 05-07-19.9 The final decision outlines
requirements for accreditation of savings from C&LM
projects; CHP efficiency and metering standards;
environmental attribute management; qualifying demand
response activities; and certificate creation, allocation, and
incorporation with the NEPOOL CIS. The DPUC reopened
the docket on August 1, 2007, to clarify the eligibility of
waste heat recovery systems added to the Class III
standard by the legislature in 2007, and to consider the
allocation of Class III credits to eligible technologies. A
decision is expected in the first quarter of 2008.10
Eligible CHP systems must be developed on or after January
1, 2006. Eligible systems that recover waste heat or pressure
from commercial and industrial processes must be installed
on or after April 1, 2007. Existing units that have been
modified on or after January 1, 2006, may earn certificates
only for the incremental output gains. A CHP system must
meet a total efficiency level of at least 50 percent. The sum
of all useful electrical energy output must comprise at least
20 percent of the technology's total usable energy output.
The sum of all thermal energy products must also constitute
at least 20 percent of the technology's usable energy output.
Annual fuel-conversion efficiency and percentages of
production will be assessed quarterly for the first year after
initial certification. After this first year, the CHP system must
demonstrate compliance with the efficiency requirements
each quarter to qualify for RECs.
Pursuant to the 2007 legislation, customers that install
Class III resources on or after January 1, 2008, are
entitled to Class III credits equal to at least one cent per
kilowatt-hour (kWh). The revenue from these credits must
be divided between the customer and the state C&LM
Fund in different ways depending on when the Class III
resources are installed, whether the owner is residential or
nonresidential, and whether the resources received state
support.11 Energy savings from demand response activities
are eligible for Class III certificates; however, the demand
response projects must be registered and participate in
the region's wholesale electricity market administered by
ISO New England, Inc. (ISO-NE).
Hawaii
Hawaii has had a mandatory RPS since 2004,12 which was
amended in 2006.13 The RPS requires 10 percent
renewable energy and renewable electrical energy to be
generated in 2010, 15 percent in 2015, and 20 percent in
2020. Existing renewables may be counted in the total.
Renewable electrical energy includes electrical energy
savings "brought about by the use of energy efficiency
technologies," including the "use of rejected heat from co-
generation and combined heat and power systems excluding
fossil-fueled qualifying facilities that sell electricity to electric
utility companies and central power projects."14
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The Hawaii Public Utility Commission (PUC) has the
authority to review the RPS every five years and
potentially extend requirements past 2020. The PUC may
also establish standards for each utility that prescribe what
portion of the RPS shall be met by specific types of
renewable energy sources, provided that at least 50
percent of the RPS is met by renewable energy sources.
In Hawaii, an electric utility company must fulfill the RPS
requirement. However, electric utilities and electric affiliates
are allowed to combine their renewable portfolios to meet
the requirements. Thus, Hawaii's program does not include a
REC trading program as such. The utilities must document
their generation directly to show compliance.
North Carolina
In August 2007, North Carolina enacted a Renewable Energy
and Energy Efficiency Portfolio Standard (REPS) requiring all
investor-owned utilities to supply 12.5 percent of 2020 retail
electricity sales from eligible energy resources by 2021.
Municipal utilities and electric cooperatives must meet a
target of 10 percent eligible energy resources by 2018. Up to
25 percent of the requirements may be met through energy
efficiency measures, including CHP. After 2018, up to 40
percent of the standard may be met through energy
efficiency and CHP.15
Under the REPS, there is no minimum efficiency
requirement for CHP. Energy from CHP is included to the
extent that the system "uses waste heat to produce
electricity or useful, measurable thermal or mechanical
energy for the retail customer's use and results in less
energy used to perform the same function or provide the
same level of service at the retail customer's facility."16
Thermal energy that is not used to generate electric power
and is measured accurately in British thermal units (Btu)
shall earn equivalent RECs based on the end-use energy
value of electricity of 3,412 Btu per kWh. Renewable
energy and CHP must have been installed after January 1,
2007, to be considered eligible.
Utilities may meet their obligations through actual
generation of electricity with eligible fuels and
technologies, through the purchase of bundled renewable
energy, by procuring unbundled RECs (each equivalent to
1 MWh) from in-state or out-of-state renewable energy
facilities, or through the implementation of energy
efficiency measures.17
The North Carolina Utilities Commission (NCUC) is
responsible for administering the RPS and may adjust or
modify the RPS schedule if it deems such modifications to
be in the public interest. The NCUC opened docket E-100
Sub 113 on August 23, 2007, to initiate rulemaking to
implement the RPS.18 A final order had not been issued as
of February 1, 2008.
Pennsylvania
Pennsylvania's Alternative Energy Portfolio Standard
(AEPS) was enacted in 2004 and amended in 2007.19
Pennsylvania has a tiered structure to its RPS, similar to
Connecticut. Both new and existing renewables are eligible
as Tier I resources. Tier II resources include demand-side
management and distributed generation systems, including
CHP. In 2007/2008, 1.5 percent of electricity sold must
come from Tier I sources with 4.2 percent from Tier II.
The Tier I standard increases to 2 percent in 2008/2009
and 0.5 percent each year thereafter, to reach 8 percent
of electricity from Tier I sources by 2020/2021. The Tier II
standard increases 2 percent every five years to reach 6.2
percent in 2010/2011 and 8.2 percent in 2015/2016. An
additional jump to 10 percent in Tier II resources by
2020/2021 is included as part of the standard.
Utilities comply with the RPS by obtaining the required
number of RECs (each equivalent to one MWh of
generation), which are tracked using the PJM power pool's
GATS. AEPS amendments in 2007 clarified that RECs are
the property of the renewable energy generator. The AEPS
contains a force majeure clause under which the
Pennsylvania Public Utilities Commission (PUC) can make a
determination as to whether there are sufficient alternative
energy resources in the market for utilities to meet their
targets. If the PUC determines that utilities are unable to
comply with the standard despite good faith efforts, the
PUC may alter the obligation for a given year. It may then
require higher obligations in subsequent years to
compensate for shortfalls.20
Washington
In 2006, Washington State passed a Renewable Energy
Standard (RES) by ballot initiative I-937.21 The initiative
requires electric utilities that serve more than 25,000
customers in the state to generate 15 percent of their
electric load from new renewables by the year 2020.
Additionally, electric utilities must identify and undertake
all cost-effective energy conservation. As of 2007, 17 of
Washington's 62 utilities will be regulated under the RES,
covering more than 80 percent of the population.22 The
RES starts at 3 percent of a utility's load for 2012 to 2015,
rising to 9 percent for 2016 to 2019, and 20 percent from
2020 forward.
Renewably fueled DG with a capacity of not more than 5
MW is eligible under the renewable portion of the RES. DG
may also be counted as double the facility's electrical
output if the utility owns the facility, has contracted for the
DG and associated RECs, or has contracted to purchase
only the related RECs.
CHP systems owned and used by a retail electric customer
to meet its own needs may be counted toward the
conservation provision in the initiative. By January 1, 2010,
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and every two years thereafter, each affected utility is
required to identify its "achievable cost-effective conservation
potential through 2019." Each utility must then issue an
acquisition target to be met during the next two years.
Utilities may count high-efficiency CHP units with a useful
thermal output of at least 33 percent of the total energy
output towards meeting their conservation targets. The
amount of energy conservation eligible towards meeting the
target will be determined based on an analysis of the
reduction in electricity consumption from the CHP system
compared to a best-commercially available technology
combined-cycle natural gas-fired combustion turbine.
Additionally, only the output used by the customer to meet
its own needs will count towards the target.23
The Washington Department of Community, Trade and
Economic Development (CTED) Energy Policy Division
released draft rules for implementing the initiative in late
2007 and early 2008. CTED expects to issue final rules by
March 4, 2008.24
Waste Heat CHPColorado, Nevada, North Dakota
Colorado, Nevada, and North Dakota all include recycled
energy or energy recovery processes as eligible
technologies within their RPS. CHP is included under each
of these definitions, but the most common type of CHP,
which recovers otherwise lost energy from a process
whose primary purpose is electricity generation, is
excluded in each case.
In Colorado, the RPS was originally passed by ballot
initiative (Amendment 37) in November 2004, and was
then increased and extended by the state legislature in
March 2007 as HB 1281.25 The expanded RPS requires
utilities to meet a target of 20 percent of electric sales
from renewable and recycled energy resources by 2020
and each year thereafter. Eligible CHP units must be
smaller than 15 MW and convert otherwise wasted heat
from exhaust stacks or pipes to electricity.
In Nevada, the RPS was initiated in 1997 and was expanded
to include energy savings from efficiency measures in 2005.
The RPS requirement is 9 percent for 2007 and 2008,
increasing 3 percent every two years to reach 20 percent in
2015 and thereafter. CHP systems are eligible under the RPS
as a qualified energy recovery process. Eligible CHP units
must be 15 MW or less, and only "the heat from exhaust
stacks or pipes used for engines or manufacturing or
industrial processes" used to generate electricity is
considered to be an eligible CHP process.26
North Dakota's legislature passed a voluntary RPS, HB 1506,
in March 2007 that establishes an objective that 10 percent
of all retail electricity sold in the state be obtained from
renewable and recycled energy by 2015. CHP systems are
eligible under the recycled energy definition by "producing
electricity from currently unused waste heat resulting from
combustion, or other processes, into electricity."27 Each retail
provider or generation supplier must conduct an economic
evaluation of new renewable and recycled energy and
consider the RPS objective and economic evaluation to
determine the electricity alternatives that best meet its
resource or customer needs.
Additional
A number of additional resources are available for
developing RPS policies.
EPA's Clean Energy-Environment Guide to Action
outlines 16 policies and programs states are
successfully implementing to increase clean energy.
Chapter 5 discusses RPS.
www.epa .gov/clea nenergy/docu ments/gta/g u ide_action_
chap5_sl.pdf
EPA's Fact Sheet, Renewable Portfolio Standards: An
Effective Policy to Support Clean Energy Supply
describes the benefits of RPS for states and how RPS
encourage CHP projects.
www.epa.gov/chp/documents/rps_fs.pdf
The Database of State Incentives for Renewable Energy
(DSIRE) is a comprehensive and continually updated
source of information on state, local, utility, and selected
federal incentives that promote renewable energy.
www.dsireusa.org
Evaluating Experiences With Renewable Portfolio
Standards in the United States (2004) provides a
comprehensive analysis of U.S. experience with RPS,
including lessons learned.
http://eetd.lbl.gov/EA/EMP/reports/54439.pdf
Projecting the Impact of RPS on Renewable Energy and
Solar Installations (2005) is a PowerPoint presentation that
estimates and summarizes the potential impacts of existing
state RPS on renewable energy capacity and supply.
www.newrules.org/de/solarestimates0105.ppt
Endnotes
1 Vermont's RPS is voluntary, but if the utilities have not met their goal by 2012,
then the RPS will become mandatory in 2013. EERE State Activities and
Partnerships, www.eere.energy.gov/states/maps/renewable_portfolio_states.cfm.
2 Rabe, B. Race to the Top: The Expanding Role of U.S. State Renewable Portfolio
Standards (2006), Pew Center on Global Climate Change,
www.pewclimate.org/global-warming-in depth/all_reports/race_to_the_top/
index, cfm.
3 www.arb.ca.gov/energy/dg/dg.htm.
www.eea-inc.com/rrdb/DGRegProject/Documents/MEDGRuleChapterl48.pdf.
www.tceq.state.tx.us/assets/public/permitting/air/Guidance/NewSourceReview/
segu_final.pdf.
www.dem.ri.gov/pubs/regs/regs/air/air43_07.pdf
4 www.epa.gov/ttn/atw/combust/turbine/turbnsps.html.
5 As of 2007, Maine is not included among the states with current RPS that
include CHP. In Maine's original RPS, requiring 30 percent eligible technologies
by 2000, CHP was considered an eligible resource. In 2007, Maine enacted a
new RPS of 10 percent renewable by 2017 and declared eligible technologies to
include only new renewable energy systems placed into service after
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September 1, 2005. CHP is not eligible under the current standard.
www.dsireusa.org/
library/includes/incentive2.cfm?Incentive_Code=ME01R&state=ME&CurrentPageI
D=1&RE=1&EE=1.
6 In Arizona, only renewably fueled CHP systems are eligible within the state's
RPS; fossil-fueled CHP systems are not eligible.
7 Connecticut Public Act No. 05-1, "An Act Concerning Energy Independence,"
www.cga.ct.gov/2005/ACT/PA/2005PA-00001-ROOHB-07501SSl-PA.htm.
8 Connecticut Public Act No. 07-242 §40-44, "An Act Concerning Electricity and
Energy Efficiency," www.cga.ct.gov/2007/ACT/PA/2007PA-00242-ROOHB-
07432-PA.htm.
9 Docket No. 05-07-19: DPUC Proceeding to Develop a New Distributed Resources
Portfolio Standard (Class III) - Decision, June 28, 2006, www.dpuc.state.ct.us/
FINALDEC.NSF/2b40c6ef76b67c438525644800692943/cad07929137a202785257
19c006ec899/$FILE/050719-062806.doc.
10 Docket No. 05-07-19: DPUC Proceeding to Develop a New Distributed Resources
Portfolio Standard (Class III) - Reopening, August 1, 2007, www.dpuc.state.ct.us/
FINALDEC.NSF/2b40c6ef76b67c438525644800692943/6a82a9c57e998dd285257
32f004aee23/$FILE/050719-080107.doc.
11 DSIRE, Connecticut Renewables Portfolio Standard,
www.dsireusa.org/libra ry/includes/incentive2.cfm?Incentive_Code=CT04R&state
=CT&CurrentPageID=l&RE=l&EE=l.
12 A Bill for an Act Relating to Renewable Energy, SB 2474, June 2, 2004,
www.capitol.hawaii.gov/session2004/bills/SB2474_HDl_.htm.
13 A Bill for an Act Relating to Energy, SB 3185, June 2, 2006,
www. capital.hawaii.gov/session2006/bills/SB3185_cd l_.htm.
14 A Bill for an Act Relating to Energy, SB 3185, June 2, 2006,
www.capitol.hawaii.gov/session2006/bills/SB3185_cdl_.htm.
15 Session Law 2007-397/SB 3, August 20, 2007,
www.ncleg.net/Sessions/2007/Bills/Senate/PDF/S3v6.pdf.
16 Session Law 2007-397/SB 3, August 20, 2007,
www.ncleg.net/Sessions/2007/Bills/Senate/PDF/S3v6.pdf.
17 North Carolina Utilities Commission, Renewable Energy and Energy Efficiency
Portfolio Standard (REPS), www.ncuc.commerce.state.nc.us/reps/reps.htm.
18 North Carolina Utilities Commission, Orders and Filings in Docket No. E-100, Sub
113, http://ncuc.commerce.state.nc.us/cgi-bin/fldrdocs.ndm/INPUT?compdesc=
Generic%20Proceeding&numret=001&comptype=E&docknumb=100&suffixl=&s
ubNumb=113&suffix2=&parml=000127195.
19 Pennsylvania Public Utility Commission, Alternative Energy Portfolio Standards,
www.puc.state.pa.us/electric/electric_alt_energy.aspx.
20 HB 1203, July 17, 2007,
www.legis.state.pa.us/CFDOCS/Legis/PN/Public/btCheck.cfm?txtType=HTM&sess
Yr=2007&sessInd=0&billBody=H&billTyp=B&billNbr=1203&pn=2343
21 Chapter 19.285 RCW: Energy independence act, November 7, 2006,
http://apps.leg.wa.gov/RCW/default.aspx?cite=19.285.
22 DSIRE, Washington Renewable Energy Standard,
www.dsireusa.org/library/includes/incentive2.cfm?Incentive_Code=WA15R&state
=WA&CurrentPageID=l&RE=l&EE=l.
23 Department of Community, Trade and Economic Development, WSR 07-20-126
Proposed Rules, December 27, 2007,
www.cted.wa.gov/DesktopModules/CTEDPublications/CTEDPublicationsView.aspx
?tabID=08JtemID=5375&MId=863&wversion=Staging.
24 Department of Community, Trade and Economic Development, 1-937
Rulemaking, www.cted.wa.gov/site/1001/default.aspx.
25 HB 07-1281 Concerning Increased Renewable Energy Standards, March 27,
2007, www.leg.state.co.us/clics/clics2007a/csl.nsf/fsbillcont3/C9BOB62160D
242CA87257251007C4F7A?open&file=1281_enr.pdf.
26 Nevada Revised Statues Annotated,
www.dsireusa.org/documents/Incentives/NV01R.htm.
27 HB 1506, An Act to establish a state renewable and recycled energy objective,
March 23, 2007, www.legis.nd.gov/assembly/60-2007/bill-text/HBI00500.pdf.
Fuel
AddendumInformation about
Combined Heat and Power (CHP)
CHP is the sequential generation of power
(electricity or shaft power) and thermal energy
from a common fuel combustion source. CHP
captures waste heat that is ordinarily discarded
from conventional power generation; typically,
two-thirds of the input energy is discarded to
the environment as waste heat (up exhaust
stacks and through cooling towers). This
captured energy is used to provide process
heat, space cooling or heating for commercial
buildings or industrial facilities, and cooling or
heating for district energy systems. CHP
facilities typically have efficiencies of 60 to 80
percent and use numerous types of
technologies, including turbines, reciprocating engines,
and fuel cells, as well as various fuels, including natural
gas, biomass, coal, and biogas. More information about
these technologies and their applications can be found in
the EPA CHP Partnership's Catalog of CHP Technologies
(www.epa.gov/chp/basic/catalog.html). Figure 2 shows
two common configurations for CHP systems.
CHP's applicability to many technologies and fuels means that it
can be applied in many different end uses and can use many
fuels. It is a well-known and well-demonstrated technology. The
United States has approximately 85 gigawatts (GW) of CHP
Figure 2 - Two Typical CHP Configurations
Steam Boiler/
Steam Turbine:
Water
Gas Turbine Or
Engine/Heat Recovery Unit:
Water
High-Pressure Steam
I
Fuel
' Steam
To Process
Source: U.S. EPA Output-Based Regulations: A Handbook for Air Regulators (2004),
www.epa.gov/chp/documents/obr_final_9105.pdf.
capacity in place as of 2007, yet the potential for substantial
expansion is great.28 In 2000, the U.S. Department of Energy
(DOE) and U.S. Environmental Protection Agency (EPA) set a goal
to double the capacity of U.S. CHP installations by 2010.
By providing electrical and thermal energy from a common
fuel input, CHP significantly reduces the associated fuel
use and emissions. Figure 3 illustrates the higher efficiency
of a CHP facility compared to a conventional system
providing the same service. In this case, both systems
provide 30 units of electric energy and 45 units of thermal
energy to the facility.
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In the conventional system, the electricity
required by the facility is purchased from the
central grid. Power plants on average are about
31-percent efficient, considering both generating
plant losses and the transmission and
distribution losses. Thermal energy required by
the facility is provided by an onsite boiler,
averaging 80 percent efficiency. Combined, the
two systems use 154 units of fuel to meet the
combined electricity and steam demand. The
combined efficiency to provide the thermal and
electric service is 49 percent.
In the CHP system, an onsite system provides
the same combined thermal and electric service.
Electricity is generated in a combustion turbine,
and the waste heat is captured for process use.
The CHP system satisfies the same energy
demand using only 100 units of fuel. This
system is 75 percent efficient.
Due to its higher efficiency compared to conventional
central-station generating systems, CHP produces
lower emissions of traditional air pollutants and carbon
dioxide, the leading greenhouse gas associated with
global climate change, than conventional generating
systems. Figure 4 shows the NOX emissions benefits of
the CHP system. The CHP system has much lower
emissions because it uses 35 percent less fuel, even if
the combustion process has the same input-based
emission rates as the conventional equipment. In this
example, as is often the case, the new CHP system
displaces higher-emitting generators on the electric
grid, and the emissions rate for the new system is
lower than the conventional alternative, further
reducing emissions. In the case shown, the CHP
system emits less than half as much NOX as the
conventional system due to a combination of greater
efficiency and lower emissions rate.
Figure 3 - Efficiency Benefits of CHP
Conventional
Generation:
Combined Heat & Power:
5 MW Natural Gas
Combustion Turbine
Losses
Power
Station
Fuel
Source: U.S. EPA Output-Based Regulations: A Handbook for Air Regulators (2004),
www.epa.gov/chp/documents/obr_final_9105.pdf.
Figure 4 - Nitrogen Oxide Emissions
Benefits of CHP
Conventional
Generation:
Power
Station
Fuel
Combined Heat & Power:
5 MW Natural Gas
Combustion Turbine
CHp
EFFICIENCY: 80%
_^. I ) Heat
Emissions
Source: U.S. EPA Output-Based Regulations: A Handbook for Air Regulators (2004),
www.epa.gov/chp/documents/obr_final_9105.pdf.
28 U.S. DOE CHP database, maintained by Energy and Environmental Analysis,
www.eea-inc.com/chpdata/index.html.
For more information, contact:
g CHP
&EPA COMBINED HEAT AND
POWER PARTNERSHIP
Katrina Pielli
U.S. Environmental Protection Agency
Phone: (202) 343-9610
e-mail: pielli.katrina@epa.gov
10
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