In order to identify opportunities for DG in critical infrastructure, it is important to first determine the most important CI sectors across the state, local jurisdiction, or utility territory, and then identify which are most conducive to different DG technologies based on sector characteristics. Ultimately, selected facilities within these defined CI sectors can be analyzed and ranked based on prioritization and the potential for installing CHP, solar + storage, or implementing a microgrid.

The objective of this section is to quickly assess a CI portfolio through a series of filters that is designed to yield high priority candidate facilities for further assessment. Users may choose to utilize only a portion of this step-by-step guide, or start from Step 1 and move all the way through to assess the potential for different DG technologies at host CI facilities. For example, states may find it useful to rank the most important CI sectors in their state (Step 1) and assess which of these sectors are the most conducive to different DG technologies (Step 2), and then move on to assessing what types of programs or policies could enable DG or CHP in these CI sectors. Cities and utilities may find it useful to move through all of the detailed steps to screen specific CI sites for individual DG technologies, such as CHP feasibility and cost-effectiveness.

The first step is to identify and rank the key CI sectors in the targeted region. This typically involves working with various stakeholder groups to determine a set of metrics to prioritize critical infrastructure sectors, with a vulnerability or risk assessment. Critical facilities can include both public and private sector buildings, which is often a consideration in the approach as well. Although approaches and metrics for each jurisdiction will differ depending on resiliency goals, the critical infrastructure sectors outlined by DHS offer a good starting point and provide information on which services are most important to maintain during an extended outage event. Users can use DHS sectors as starting point, and apply resiliency goals and criteria to each sector to help rank top CI sectors. The following table is an example of how NYSERDA approached evaluating the most critical sub-sectors to maintain during an emergency.

Consequence Category	Measurement Criteria
1. Human Impact	Measured in terms of the fatalities or injuries that could result if the critical asset is degraded or incapacitated by the worst reasonable case power outage
2. Economic Impact	Measured in terms of the direct and indirect effects on the economy (e.g., cost to rebuild asset, cost to respond to and recover from disaster, downstream costs resulting from disruption of product or service, long-term costs due to environmental damage) that could result if the critical asset is degraded or incapacitated by the worst reasonable case power outage
3. Impact on Public Confidence or Psychological Consequences	Measured in terms of the effect on public morale and confidence in national economic and political institutions that could result if the critical asset is degraded or incapacitated by the worst reasonable case power outage
4. Impact on Government Continuity	Measured in terms of the reduction in the ability of state and local governments to deliver minimum essential public services, ensure public health and safety, and carry out national security-related missions if the critical asset is degraded or incapacitated by the worst reasonable case power outage

The following list is an example of how a community might rank a list of top CI sectors, as a result from applying resiliency goals and criteria to the DHS CI sectors. (see Table 1 below).

Examples of processes individual states have used to identify key CI sectors are shown below:

The second step is to take the CI sector list in Step 1 and to identify the specific CI sub-sectors in that list that have the technical characteristics (e.g., potential electric and thermal loads) to support CHP, solar + storage, and/or microgrids, and eliminate other sectors/sub-sectors that do not. While most facilities currently rely on diesel generators for backup power in the event of a grid outage, there have been cases where diesel generators have not performed as expected for a variety of reasons. Therefor, this section will focus on technologies that can operate continuously and/or provide different types of benefits to CI facilities, such as CHP. Diesel generators can still provide the required backup power if engineered and configured correctly, but are not analyzed in this context.

The third step is to perform an individual site assessment for potential CI sites based on the conducive sub-sectors identified in Steps 1 & 2 above. The following tools can be used to screen individual CI sites for their potential to deploy CHP, solar + storage, and/or a microgrid for increasing energy resilience.

Users may choose to perform individual site screening assessments using the tools detailed (below), or learn more about individual DG technologies and the potential resilience benefits they may provide to individual CI sites (right).		Learn more about CHP for Resilience
		Learn more about Solar + Storage for Resilience
		Learn more about Microgrids for Resilience

Individual Site Assessment Tools

CHP Site Screening Tool	The CHP Site Screening Tool is an excel-based tool that can provide an individual site screening assessment for CHP based on a variety of user inputs and pre-determined metrics.	CHP Site Screening Tool
Solar + Storage Screening Tool	NREL's REopt model is used to optimize energy systems for buildings, campuses, communities, and microgrids.	REopt Tool
Microgrid Modeling Tools	The following microgrid modeling tools provide a variety of options for users looking to assess and optimize potential microgrid resources and configurations	HOMER Energy DER-CAM RETScreen

Contact your Onsite Energy TAP with sites identified for further analysis. If your facility received a payback of under 10 years and qualified as having either high (green) or medium (yellow) CHP potential, you should contact your Onsite Energy TAP. Onsite Energy TAPs can provide a more in-depth analysis and additional services, such as a qualification screening or feasibility analysis for individual sites. Onsite Energy TAPs can also provide additional resources for individual project implementation.

Now that you’ve defined which critical facilities are the highest priority, there are several ways you can take action to ensure state policies and programs support CHP deployment at these sites. By reviewing statutes and/or regulations already in place, state and local policymakers can ensure that policies are consistent with objectives to enhance the resiliency of critical infrastructure with CHP. States may also consider designing new programs targeting critical infrastructure applications. In this step, we provide policymakers and utility regulators with best practice policy recommendations to assist them in aligning key state policies to support CHP.

• Interconnection Standards
• Standby Rates
• Portfolio Standards
• State Efficiency and Clean Energy Programs
• Utility Incentive Programs
• Air Permitting
• Local Project Permitting and Codes

Interconnection

Standardized interconnection rules typically address the technical requirements and the application process for DG systems, including CHP, to connect to the electric grid. Most CHP systems are sized to provide a portion of the site’s electrical needs, and the site continues to remain connected to the utility grid system for supplemental, standby, and backup power services, and, in select cases, for selling excess power.

A key element to the market success of CHP is the ability to safely, reliably, and economically interconnect with the existing utility grid system. Uncertainty in the cost, timing, and technical requirements of the grid interconnection process can be a barrier to increased deployment of CHP. While developing state standards or revising existing standards, the following elements have been used successfully by states across the country:

• Appropriate interconnection fees. High application and technical study fees associated with interconnection, along with high insurance requirements, can easily impair CHP project economics. Thus, some states have turned to a more effective approach—setting upper and lower bounds on application and study fees commensurate with the size of the system and potential safety impacts on the grid, and sometimes waiving application fees for small CHP systems completely. In general, interconnection fees should be just and reasonable and reflect the true costs of interconnection.
• Streamlined procedures with decision tree screens (allowing faster application processing for smaller systems and those unlikely to produce significant system impacts). A criticism of some state interconnection standards is the lengthy approval process and complicated application requirements. To facilitate rapid application turnaround, successful state interconnection standards have well-defined application processing timelines and simple decision trees that show, based on the system size and other characteristics, which interconnection procedures apply. For example, Colorado has a streamlined process for systems up to 2 MW that involves several different screens to determine if more detailed review is needed. If a proposed project fails one of the screening tests the owner may have to pay for additional tests or move to the next level analysis.
• Standardized Technical Requirements. Standardization of technical and safety requirements ensures consistent safety for the utility, lessens the complexity of the interconnection process, and helps reduce costs for some project developers by alleviating the need to hire expert consultants. States commonly specify technical requirements based on national safety standards—IEEE 1547 and UL 1741—or use these two standards as a basis for developing their own requirements. These two standards focus on the technical specifications for, and testing of, the interconnection itself. They provide guidelines relating to the performance, operation, testing, safety considerations, and maintenance of the interconnection and form the basis of many state standards.
• Standardized, simplified application forms and contracts. Providing standardized and readily accessible interconnection application and contract forms to end-users and project developers is important. Standardized forms used by all utilities in the state helps state regulators assess the interconnection process and handle disputes, and also make it easier for project developers to comply with requirements. For example, Maryland’s interconnection application forms are limited to eight pages. Massachusetts proposed the creation of a uniform on-line interconnection application form, and California has a model interconnection application in investor-owned utilities to adopt.
• Defined process to address disputes. A defined process to address interconnection disputes between an end-user and a utility if an impasse is reached is important. Con Edison appointed a Distributed Generation Ombudsperson in 2002 in response to increased customer interest and the role was formalized in a 2005 order (CASE 04-E-0572) from the New York State Department of Public Service. Massachusetts has proposed requiring that an arbitrator is hired to resolve any disputes in its interconnection process. Other states have dispute resolution clauses in their interconnection standards including Hawaii, Colorado, and Maryland.
• The ability for larger CHP systems and those not captured under net metering rules to qualify under the interconnection standards. Some states only allow for relatively small systems to interconnect under streamlined standards, often assuming that smaller DG systems are more likely to produce power primarily for their own use. In states with a multi-tiered interconnection process, small systems that meet IEEE and UL standards or certification generally pass through the interconnection process faster, pay less in fees, and require less protection equipment because there are fewer technical concerns. However, restricting capacity limits for streamlined interconnection standards to only small systems does not help facilitate broad investment in all sizes of CHP in applications where it makes economic sense. State regulators can consider the size threshold for streamlined standards that is appropriate for their states.
• Allow CHP systems to interconnect to both radial and network grids. Network grids are present in many large cities where a significant amount of CHP potential exists. Interconnection, particularly in network or local distribution networks, present protection and grid operational challenges to address inadvertent back feed into the local grid that can cause safety concerns and failure to serve loads. However, with careful operational planning and system protection review, DG can be accommodated. It is important to allow interconnection to both radial and network grids, with protections in place to minimize system impacts, in order to realize the full potential of CHP.

Interconnection Resources

• SEE Action Guide to Successful Implementation of State CHP Policies. Chapter 3 of this Guide, prepared by the State and Local Energy Efficiency Action Network (SEE Action), co-facilitated by the US DOE and the US EPA, provides an overview of issues associated with interconnection standards and provides additional detail on the key elements and approaches described above.
• Interstate Renewable Energy Council’s Model Interconnection Procedures. IREC’s Model Interconnection Procedures synthesize a number of best practices in the evolution of safe and reliable connecting to the utility grid. It is a free resource intended for states to use as they develop and/or refine their own rules for interconnection. The goals of the model procedures are to “streamline the regulatory process, save state resources, and avoid the need to reinvent the wheel on interconnection.”
• Freeing the Grid: Best Practices in State Net Metering Policies and Interconnection Procedures. Produced by IREC and Vote Solar, “Freeing the Grid” is an annual report card that rates all 50 states on net metering and interconnection standards. It is an online resource that includes best practice guidelines and an interactive map with state grades and recommendations designed to help state policy makers, regulators, advocates and other stakeholders easily understand and improve their policies.

Standby Rates

Standby rates are charges typically paid by commercial and industrial customers that operate onsite generation systems, but remain connected to the grid in order to access services from an electric utility such as supplemental, standby, and backup power. Without appropriately designed rate structures for these services, the financial viability of a CHP project can be significantly reduced.

The following features can be incorporated into a standby rate regime consistent with standard ratemaking principles, avoiding cost shifting from CHP customers to other customers, providing appropriate incentives to operate CHP facilities in a manner most efficient for the utility system as a whole, and aligning the economics for the CHP facility with the cost to serve that customer:

• Reflect load diversity of CHP customers in charges for shared delivery facilities. Charges for transmission facilities and shared distribution facilities such as substations and primary feeders should reflect that they are designed to serve customers with diverse loads. Load diversity can be recognized by designing demand charges on a coincident peak demand basis as well as the customer’s own peak demand and by allocating demand costs primarily or exclusively to usage during on-peak hours.
• Allow the customer to provide the utility with a load reduction plan. The plan should demonstrate its ability to reduce load within a required timeframe and at a specified amount to mitigate all, or a portion of, backup demand charges for local facilities. This allows the standby customer to use demand response to meet all, or a portion of, its standby needs.
• In states with retail competition, offer a self-supply option for reserves. This can be in the context of the load reduction plan discussed above, through utility-controlled interruptible load, or some other means that can both save costs for the customer and avoid costs for the utility. The self-supply plan can be structured to reflect actual performance of the customer over time.
• Offer daily, or at least monthly, as-used demand charges for backup power and shared transmission and distribution facilities. Moving away from annual ratcheted charges gives the CHP customer a chance to recover from an unscheduled outage without eroding savings for an entire year. Daily charges encourage customers to get their generators back online as quickly as possible.
• In states with retail competition, allow customer-generators the option to buy all of their backup power at market prices. The customer can avoid any utility reservation charge for generation service because the utility is relieved of the obligation to acquire capacity to supply energy during unscheduled outages of the customer’s CHP unit.
• Schedule maintenance service at nonpeak times. In general, because this service can be scheduled for nonpeak times, it creates few additional or marginal costs to the utility’s system, and tariffs can be structured to exempt the customer from capacity-related costs (e.g., reservation charges or ratchets, for either generation or delivery).
• Provide an opportunity to purchase economic replacement power. During times of the year when energy prices are low, the utility can provide on-site generators energy at market-based prices at a cost that is less than it costs to operate their CHP systems, and at no harm to other ratepayers. Such arrangements must be compatible with the structure of retail access programs, which the CHP customer may otherwise be relying on, and should allocate any incremental utility costs of purchasing such power (including general and administrative fees) to the CHP customer.

Standby Rates Resources

• SEE Action Guide to Successful Implementation of State CHP Policies. Chapter 2 of this Guide, prepared by the State and Local Energy Efficiency Action Network (SEE Action), co-facilitated by the US DOE and the US EPA, provides a detailed explanation of what standby rates are, how they are designed, and how they can be improved. It explains successful implementation approaches by utilities operating in different states including Pacific Power (Oregon), ConEdison (New York), and Georgia Power (Georgia).
• 5 Lakes Energy “Apples to Apples” Standby Rate Analyses. 5 Lakes Energy has conducted several analyses of standby rates for Ohio, Minnesota, Michigan, and Pennsylvania that compares monthly bills across a variety of outage scenarios to demonstrate the impact of widely varying standby tariffs on current and potential CHP customers. One of the studies found that a Pennsylvania company with a 2 MW CHP system with no outages would be required to pay standby fees ranging from roughly $5,200 to over $11,500 each month in standby fees, depending on where the system is located. Findings from these studies have been considered by state regulators exploring best practices in standby rate design.
• National Regulatory Research Institute’s report, Electric Utility Standby Rates: Updates for Today and Tomorrow. This paper reviews current practices for standby tariffs and presents options and recommendations about how to determine an appropriate standby rate, reflecting differences among generators (such as size and type of generator) and how the generators are regularly operated. In particular, it explores and reports on standby rates and differences between vertically integrated monopoly and competitive electricity markets.
• Standby Rates for Customer-Sited Resources: Issues, Considerations and the Elements of Model Tariffs. This report was prepared by Regulatory Assistance Project and ICF International for the U.S. Environmental Protection Agency’s CHP Partnership. It provides a primer on the basics of electric service and rate design and a detailed assessment of the effects of three tariff existing designs on a prototype CHP facility in Oregon, New York, and Massachusetts. The report suggests features and approaches to standby rates that provide appropriate savings to DG customers and appropriate cost recovery to the utility.
• Standby Rates for Combined Heat and Power Systems: Economic Analysis and Recommendations for Five States. This report, prepared for Oak Ridge National Laboratory, presents the results of an analytical assessment of the rates, terms, and conditions for standby service for CHP systems in five states: Arkansas, Colorado, New Jersey, Ohio, and Utah. It sets forth options to improve tariffs analyzed and estimate the impact of these improvements for a set of utility customers with CHP systems.

Clean Energy Portfolio Standards

Clean energy portfolio standards, including energy efficiency resource standards and renewable energy portfolio standards, can be used by states to successfully increase the use of clean energy. A number of states have explicitly included CHP as an eligible resource within a portfolio standard, including renewable portfolio standards (RPS), energy efficiency resource standards (EERS), and alternative portfolio standards.

• Renewable portfolio standard (RPS) is the most common form of a portfolio standard and is usually focused on traditional renewable energy such as wind, solar, and biomass projects. This type of portfolio standard may incorporate other technologies and fuel types in addition to renewable energy and may have separate tiers or target mandates based on the form of generation. Connecticut is an example of a state with CHP included in an RPS.
• Energy efficiency resource standards (EERS) require utilities to save a certain amount of energy every year. To do this, utilities implement energy efficiency programs to help their customers save energy in their homes and businesses. Some states include CHP and other efficient distributed generation technologies. Many states have an EERS and a separate RPS, but some combine an RPS and EERS into one comprehensive portfolio standard program. Michigan is an example of a state with renewable energy standard (RES) that combines targets for renewable energy generation and energy savings requirements.
• Alternative energy portfolio standards (APS) often set targets for a certain percentage of a supplier’s capacity or generation to come from alternative or advanced energy sources such as CHP, coal with carbon capture and storage (CCS), coal co-fired with biomass, or municipal solid waste projects. These standards are often market-based and credit eligible projects with alternative energy credits or some other form of credit, which can then be purchased by electricity suppliers to meet compliance obligations. Examples of states with APS' that include CHP are Massachusetts and Pennsylvania.

State regulators should focus on the following three implementation approaches when implementing CHP as a resource within a clean energy portfolio standard:

• Qualifying resources definition—how CHP is defined. A key component of CEPS is the definition of technologies and fuels that qualify towards compliance with the standard. This decision may be made in legislation or by the utility commission as part of implementing the standard, or by other policymakers. How CHP is defined in a CEPS varies by state. For instance, some state CEPS only allow for bottoming cycle CHP systems (waste heat recovery or waste heat to power) to qualify, some states allow for all types of CHP regardless of fuel type, whereas other standards may only allow for renewable-fueled CHP to qualify.
• Minimum efficiency requirements or performance-based metrics. An efficiency threshold for CHP projects is an important feature of incorporating CHP in CEPS. An appropriate eligibility threshold for CHP systems is one that is set high enough so that it is clear the CHP is achieving energy savings compared to separate heat and power, but not at a level that many CHP systems considered to be “high efficiency” would be excluded. Connecticut, Ohio, and Washington are examples of states with minimum efficiency requirements. As an overlay or as a stand-alone policy, progressive incentives for greater energy efficiency requirements in CEPS can also serve as a market driver for the development of systems with greater efficiency. For example, the Massachusetts Alternative Portfolio Standards uses a performance-based metric instead of a minimum efficiency threshold to encourage highly efficient CHP systems.
• Separate, distinct targets for CHP and other technologies. Establishing separate targets or tiers for different categories of resources ensures that a certain class of resource is not encouraged to the detriment of others. If a policy goal is to encourage diversity of supply, this can also help achieve the goal. The following are two state implementation approaches that have proven effective:
  • To set a separate tier for CHP and related energy efficiency technologies and require a specified percentage of the target to be met by each of these tiers (Connecticut’s Class III and Pennsylvania’s Tier II).
  • To establish a separate portfolio standard program (distinct from the RPS) which is devoted to CHP and/or other energy efficiency technologies (Massachusetts’ APS and Michigan’s Energy Optimization Savings Standard).

Clean Energy Portfolio Standard Resources

• SEE Action Guide to Successful Implementation of State CHP Policies. Chapter 5 of this Guide, prepared by the State and Local Energy Efficiency Action Network (SEE Action), co-facilitated by the US DOE and the US EPA, provides an overview of portfolio standards and how states can use them to increase adoption of clean energy technologies, including CHP. It provides additional detail on the key elements and approaches described above, including a table detailing states with CHP eligibility in RPS, EERS, or APS and the characteristics of the policy.
• Portfolio Standards and the Promotion of Combined Heat and Power. This report, prepared for EPA’s CHP Partnership, discusses the different ways CHP is incorporated in portfolio standards. It presents the basic portfolio standard design approaches, identifies key CHP-related issues for policymakers to consider when revising or developing portfolio standards, and provides state-specific information on existing standards that allow for CHP.

State Efficiency and Clean Energy Programs

States have used a number of policy instruments to provide financial support for distributed generation and CHP deployment. Policy and program options can include tax credits, bonds, loans or loan guarantees, project grants, and property assessed clean energy (PACE) programs. State efficiency and clean energy programs that are designed with broad applicability are most likely to encourage CHP and policymakers should consider developing eligibility criteria that can apply to a range of system sizes, allow all fuel types, and are not restricted to a single sector. The following describes each policy option and offers basic state examples.

• Tax credits: State or federal tax credits or favorable tax treatment can support CHP projects or activities, either specifically or where eligibility includes CHP. For example, in Florida, the purchase of eligible CHP equipment is exempt from the state’s sales and use tax.
• Bonds: State or federal bonds can support CHP projects or activities by establishing a means to borrow capital for CHP projects at a fixed and often lower interest rate. For example, New Mexico’s Clean Energy Revenue Bond Program, enacted in 2005, authorizes up to $20 million in bonds to financing clean energy projects in state government agencies and schools, paid back to the bonding authoring using savings on energy bills.
• Loans or loan guarantees: State or federal loans can support CHP projects or activities (either specifically or where eligibility includes CHP) by financing the purchase of CHP systems and equipment, often at very low interest rates. For example, Connecticut's low-interest loan program, in effect since 2006, provides loans at a subsidized interest rate of 1 percent below the applicable rate or no more than the prime rate to customers for the installation of distributed generation systems, including CHP, with a capacity range of 50 kW or greater.
• Grants: State or federal grants can support CHP projects or activities by financing the development and purchase of CHP systems and equipment. For example, the Maryland Energy Administration provides grants up to $500,000 per project to encourage the implementation of CHP at industrial and critical infrastructure facilities, including healthcare, wastewater treatment, and essential state and local government facilities. This state grant program is in addition to the utility incentive programs offered by Maryland electric utilities.
• C-PACE: Commercial Property Assessed Clean Energy (PACE) programs allow building owners to receive financing for eligible energy-saving measures that can include CHP, repaid as property tax assessments over a period of years. For example, San Francisco has a commercial PACE program called GreenFinanceSF, which offers loans of up to 10 percent of the assessed value of a property to eligible CHP systems.

State Efficiency and Clean Energy Programs Resources

• EPA’s Energy and Environment Guide to Action. Chapter 6 of this guide provides in-depth information about CHP policies and programs that states are using to meeting their energy, environmental, and economic objectives. Table 6.1 summarizes each type of CHP-related policy, including incentives, currently in place in many states and classifies them into four categories: environmental, energy, financial, and utility.
• Database of State Incentives for Renewables and Efficiency (DSIRE). The N.C. Clean Energy Technology Center administers an online database funded by DOE, providing comprehensive information on incentives and policies that support renewable energy and energy efficiency in the US. Users can select their state to identify what policies are in place and which technologies are eligible.

Utility Incentive Programs

States can encourage utilities to develop and implement CHP-specific incentive programs within their portfolio of energy efficiency programs. Many utilities consider CHP as an available efficiency measure in their “custom” programs for commercial and industrial (C&I) customers. However, this approach may not be sufficient to significantly encourage the adoption of CHP. CHP is typically more capital-intensive than other C&I efficiency measures and involves more complex procedures like environmental permitting, interconnection applications, feasibility assessments and other procedures that simpler measures do not require. Expertise in navigating this complex process is key to CHP adoption, which is why some states have encourage their utilities to develop standalone CHP programs that can provide this focused expertise.

There are a number of different CHP program incentives structures, eligibility requirements, and design parameters, but utilities with specific CHP programs in their energy efficiency portfolio share several common incentive structures. Utilities typically offer two major types of incentives for CHP programs; capacity incentives and production incentives.

• Capacity incentives. Capacity incentives are typically issued on a $/kW basis to help buy down the initial capital outlay for a customer. Systems must typically meet a minimum efficiency requirement to qualify for the incentive. Utilities may offer capacity incentives of different amounts at different stages throughout project development:
  • Design Phase – Design capacity incentives are issued upon submission of a commitment letter and review of system design specifications. This model helps to not only lower the initial capital outlay for a customer, but also lower the project risk. This type of incentive is the simplest to administer, as it requires only a review of design specifications and performance estimates. For example, ComEd, the largest electric utility in Illinois, offers a few interesting variations on a standard design incentive, for example, offering to pay 50% of the cost of a feasibility assessment and 50% of an interconnection fee—up to a cap.
  • Installation Phase – Installation capacity incentives are issued upon system commissioning and inspection. These incentives are typically issued in a tiered system based on project size. For example, Baltimore Gas & Electric (BG&E) and Pepco are two utilities in Maryland that offer this incentive. Separating the design and installation incentives into two parts adds some administrative complexity, but ensures that the system is installed according to the design specifications.
• Production incentives. Production Incentives are issued on a $/kWh basis for electricity that is produced for a certain period of time after the system is operational. Typical timeframes for production incentives are in the range of 18 months to 5 years. These incentives help ensure that the system is operated efficiently and properly maintained. While production incentives do not help with the barrier of high upfront capital investments for CHP, they do provide a guaranteed cash flow for the project after it becomes operational and meets the measurement and verification requirements.

Many utilities have administered CHP incentive programs, including:

• AEP Ohio
• Baltimore Gas and Electric
• Commonwealth Edison
• Consolidated Edison
• Delmarva Power
• Dayton Power and Light
• Eversource
• FirstEnergy's Pennsylvania Utilities
• National Grid (Massachusetts)
• National Grid (Rhode Island)
• Nicor Gas
• PECO
• Pepco
• Pacific Gas and Electric
• Philadelphia Gas Works
• PPL Electric Utilities
• Puget Sound Energy
• Southern California Edison
• San Diego Gas and Electric
• Southern California Gas Company
• Southwest Gas
• UGI Utilities

Utility Incentive Program Resources

• Utility Combined Heat and Power Programs—the Hot New Trend in Efficiency. This whitepaper prepared by ICF International helps explain why a utility should consider including CHP as part of an energy efficiency portfolio and describes different program and design options available to utilities. In addition, it provides an example utility CHP program structure and shares ideas about how a utility can go about setting up a program.
• EPA’s report on Utility Incentives for CHP. This report describes the results of EPA’s research and analysis into utility incentives for CHP. It provides information about utility-initiated policies, programs, and incentives. It was prepared in 2008 and may provide useful historical information.

Air Permitting

To ensure CHP systems are in compliance with air quality standards, a facility, in consultation with the state or local permitting agency, reviews air permitting requirements and must obtain a permit before the system is installed and operated. The process for obtaining air permits can be time-consuming and resource-intensive, so several states have introduced procedures to simplify and speed up the permitting process for certain types of CHP units. Another tool for encouraging CHP deployment is the development of output-based emissions regulations, which recognize the efficiency and environmental benefits of CHP when regulating their emissions. States should consider the following options for air permitting policy options that can support CHP:

• Streamlined permitting procedures. States may choose to develop alternatives to conventional air permits that streamline the permitting process for both the permitting authority and the facility being regulated. The purpose is to reduce the time and cost involved in permitting for eligible CHP units by consistently applying requirements that are predetermined by the state, although they may not apply to all CHP prime movers and fuel types. There are two approaches to streamlining permitting procedures – permits-by-rule and general permits – which are designed similarly but implemented differently.
  • Permits-by-rule (PBRs) - PBRs are established as part of a state’s regulations. Facilities that elect to obtain a PBR notify the permitting authority that they are utilizing the PBR and agree to comply with all of the requirements of the PBR. There is no permit application, no permit development process, and no public notice period. Sources are not issued a PBR; instead, they construct and operate under the requirements of the regulation. A source constructed and operated under a PBR is required to notify or register with the permitting authority. Procedures vary, and at times, an approval is not necessary.
  • General permit (GPs) - GPs are developed according to procedures found in state regulations and can be expeditiously approved to permit a specific system. However, sources applying for a GP may need to wait for approval depending on the state permit jurisdiction.
• Output-based emissions regulations (OBRs). States have found that OBRs can be effective tools for promoting CHP by relating emissions to the productive output of the energy-consuming process, instead of the amount of fuel burned. OBRs define emissions limits based on the amount of pollution produced per unit of useful output, accounting for the unit’s efficiency (e.g., pounds of sulfur dioxide per MWh of electricity). By contrast, input-based regulations are based on the amount of fuel burned and do not reflect a unit’s efficiency. Electricity generation technologies, including CHP, have traditionally been subject to input-based emissions regulations, but OBR can be used to credit all of the useful energy generated. For CHP system owners, OBR can provide greater flexibility and lower compliance costs by accounting for both the thermal and electric energy they produce. As of December 2014, 19 states have adopted some form of output-based regulation. The steps for developing an output-based emission standard are:
  • Develop the output-based emission limit. The method that is used will depend on whether or not measured energy output data are available.
  • Specify a gross or net energy output format. Net energy output more comprehensively accounts for energy efficiency, but can increase the complexity of compliance monitoring requirements.
  • Specify compliance measurement methods. Output-based standards require designating methods for monitoring electrical, thermal, and mechanical outputs. Instruments to continuously monitor and record energy output are routinely used and are commercially available at a reasonable cost.

Air Permitting Resources

• EPA’s Fact Sheet on “Approaches to Streamline Air Permitting for CHP: Permits by Rule and General Permits.” This fact sheet provides background and a description of the process for developing streamlined air permitting through permit by rule and general permits. It summarizes the permit by rule and general permit programs developed in Connecticut, New Jersey, and Texas based on interviews with representatives from those states. Research documents reasons for developing expedited permitting programs, the processes they followed to develop them, the requirements they established, and observations on the process and outcomes achieved.
• EPA’s Handbook for Air Regulators on Output-Based Regulations. The EPA’s CHP Partnership developed this handbook to assist air regulators in developing emission regulations that recognize the pollution prevention benefits of energy-efficient generation and renewable energy technologies. It describes output-based regulations, explains the benefits, shows how to develop an output-based standard or how to comply with one, and provides a catalogue of the current use of output-based regulations for combustion sources.

Local project Permitting and Codes

When installing a CHP system, facilities are required to obtain permits from local authorities to ensure it is constructed and operated in compliance with local and state regulations. The number of permits and approvals will vary depending on project characteristics such as the size and complexity of a project, the geographic location, the extent of other infrastructure modifications (e.g., gas pipeline, distribution), and the potential environmental impacts of construction and operations. Coordination with local agencies, such as the city or county planning agency, fire department/authority, building department, environmental health department, and others is needed. However, many local agencies have limited to no experience with CHP projects, which can create delays or difficulties in the CHP project development process. Policy makers can help streamline CHP installations by including education about CHP during permitting codes and inspector training.

Local project Permitting and Codes Resources

• EPA’s Procurement Guide: CHP Siting and Permitting Requirements. The EPA’s CHP Partnership developed this guide to help explain the essential steps in permitting and siting CHP systems. It documents the typical types or permits or approvals that are required, describes the overall permitting process and goes in depth in several key areas. Section 5 focuses on “Local Zoning/Planning Requirements,” and discusses the local regulatory agencies that may be involved in permitting a CHP project.