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Recent developments in technology as well as federal regulations are expanding electrical grid management opportunities using demand response.  Demand response (DR) refers to a number of programs designed to reduce load on the electrical grid by methods such as load shifting from peak hours, energy efficiency techniques, and/or load shedding by use of on-site electrical generation.  These programs offer financial incentives for participants from the industrial, commercial, and institutional sectors where the use of an existing emergency generator as a demand-side resource is a promising option.  This article outlines the key air permitting considerations when evaluating the use of on-site generation as a potential DR resource.

Demand response is defined as follows:

“Changes in electric usage by end-use customers from their normal consumption patterns in response to changes in the price of electricity over time, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized.”1

Standby GeneratorAlthough numerous programs exist, for the purposes of air environmental regulations, demand response can be classified as either:

  • Emergency Demand Response – typically defined as a demand response program in which a facility curtails on-site electricity demand only during Regional Transmission Organization RTO)-declared emergencies (when system capacity or reliability is in jeopardy)
  • Economic Demand Response – a program in which a facility is provided economic incentive to curtail on-site electricity demand from the grid when prices are high (i.e., typically during peak electricity demand periods)

DR program participants can maximize financial benefits by lowering electricity use from the grid by a combination of strategies such as changing normal consumption (lighting, air conditioning, ventilation, process heating and cooling, scheduling of production) and/or by using on-site power generation capabilities.

Recent Developments Advancing Demand Response

Electrical grid capacity expansion is an expensive and lengthy process.  Demand response minimizes transmission infrastructure issues by providing energy closer to where it is needed.  As such, many federal and state laws have promoted demand response.  The federal laws have resulted in regulation that ensures the competitiveness of organized wholesale energy markets and removes barriers to the participation of demand response resources.  Recently, state laws have also been established setting goals for energy efficiency and demand response grid curtailments.

Another factor that may advance the demand response market is the implementation of several air quality rules affecting the electric power generation sector.  These rules will impact competitive market pricing for energy during peak demand as utility companies install additional emissions controls to comply with the new regulations.  Additionally, older under-controlled coal-fired plants will likely be retired rather than upgraded to comply with the new rules such as:

  • Cross-State Air Pollution Rule (CSAPR)2
  • Mercury and Air Toxics Standards (“Utility MACT”)
  • GHG Tailoring Rule
  • NSPS for GHG from fossil fuel power plants (pending proposed rule)

Technological advances in real time metering have further promoted demand response.  Newer meters not only measure energy use but also record the time interval of use allowing for dynamic pricing.  Advanced metering also allows for two-way communication, further facilitating demand response.

Emergency Generators Used for Demand Response

Organizations Involved in the Electricity Markets

The Federal Energy Regulatory Commission (FERC) is a governmental agency that regulates the transmission of electricity as well as natural gas and oil. In the U.S., the electric transmission grid is administered by Regional Transmission Organizations (RTO) or Independent System Operators (ISO). These RTO/ISOs are third party organizations whose role is to eliminate conflicts of interest that would occur if the producers also controlled the distribution system. RTO/ISOs engage in regional planning to ensure reliability and grid infrastructure as well as market competition. Electricity is bid in the wholesale market place from a variety of sources. Industrial, commercial, and institutional demand response participation in the wholesale market is implemented through agents called Curtailment Service Providers (CSP). Demand response is a fast growing element of the wholesale electricity market where peak demand is augmented with load reductions in lieu of power generated at power plants.

As mentioned above, typical demand response participants are commercial, institutional, and industrial customers with high load requirements.  Facilities such as data centers, hospitals, universities, hotels, and most industrial sites typically install back-up generators for use in the event of power failures.  These existing emergency generators typically have a capacity of 500 kilowatt (kW) or more and are equipped predominantly with diesel-fired stationary internal combustion engines (ICE).

The federal air emissions regulations applicable to stationary engines differentiate between emergency use and non-emergency use when determining what emissions limitations and other requirements apply.  Further, participation in either Economic DR or Emergency DR and the number of hours of participation will be a factor in determining if the ICE is classified as emergency or non-emergency use.  In general, these federal rules do not categorically prohibit an existing “emergency” generator from participating in demand response, but rather outline the specific standards that must be complied with for that use.  Specific case-by-case review of each engine under consideration for demand response is required to ensure compliance with federal, state, and local regulations.

The New Source Performance Standards (NSPS) regulate criteria pollutants from engines classified as “new” by the rules.  Hazardous air pollutants from “existing” engines and certain new engines are regulated under the National Emission Standards for Hazardous Air Pollutants (NESHAP).  Each regulation contains emissions limitations, work practice standards, emissions testing, monitoring, recordkeeping, and possibly reporting requirements that vary depending on criteria such as the type of engine use , maximum power rating, date of manufacture, and the date construction commenced.  The standards listed here are discussed in more detail below with respect to how they may impact demand response participation:

  • 40 CFR Part 63, Subpart ZZZZ – National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines (NESHAP ZZZZ or RICE NESHAP)
  • 40 CFR Part 60, Subpart IIII – Standards of Performance for Stationary Compression Ignition Internal Combustion Engines (NSPS IIII or CI ICE NSPS)
  • 40 CFR Part 60, Subpart JJJJ – Standards of Performance for Stationary Spark Ignition Internal Combustion Engines (NSPS JJJJ or SI ICE NSPS)
NESHAP ZZZZ and Demand Response Participation

Understanding whether an engine is considered emergency or non-emergency dictates the emissions limitations, work practice standards, testing that may be applicable.  NESHAP ZZZZ requirements will also vary based on the specific site’s classification as a major or area source of HAP and whether the engine is considered to be “new” or “existing.”  NESHAP ZZZZ requirements were expanded to include existing engines and such engines must comply with these requirements by 2013.  Most commercial and institutional sites considering DR would be classified as area HAP sources.  At an area source of HAP, an engine is existing if construction commenced prior to June 12, 2006 and the engine has not been reconstructed since that date.3 At commercial or institutional area sources, existing emergency RICE have no requirements under the NESHAP (but must comply with the emergency use restrictions to qualify for the exemption).  Therefore, many of the commercial and institutional sectors such as hospitals, universities, and hotels, under consideration for DR programs, currently qualify for the exemption and must evaluate how DR participation will impact rule applicability.

Federal Laws and Response

Two key Federal laws have promoted demand response.  The energy Policy Act of 2005 required a study and report on the national benefits of demand response.  Later, the energy Independence and Security Act of 2007 required the National Action Plan on demand response be developed and implemented. Based on these laws, FERC established regulatory orders that have promoted demand response including:

  • FERC Order 719 which required grid operators to accept bids from demand response resources in RTOs and ISOs markets on the same basis as they do generation.
  • FERC Order 745 which recently required that demand response resources must be compensated for the service provided to the energy market price for energy.

Under NESHAP ZZZZ, the definition of emergency stationary RICE specifically excludes all Economic DR by excluding engines that are “used to supply power to an electric grid or that supply non-emergency power as part of a financial arrangement with another entity,” regardless of a source’s status as an area or major source of HAPs.  As such, all applicable engines participating in an Economic DR program must comply with the non-emergency use standards under the NESHAP.  Non-emergency engines of typical DR unit size are subject to numerical emissions limits that could require retrofit controls whereas their emergency use counterparts would only be subject to work practice standards.  New engines at area HAP sources (installed on or after June 12, 2006) comply with NESHAP ZZZZ by complying with NSPS IIII or JJJJ (as discussed in the following section).  Existing diesel engines at area HAP sources (installed prior to June 12, 2006) must comply with NESHAP ZZZZ by May 3, 2013.

However, the rule currently contains an allowance under 40 CFR 63.6640(f) for limited participation in an Emergency DR program for certain engines.4  The allowance currently specifies that 15 hours per year of the engine’s allotted maintenance run time may be used for Emergency DR “if the regional transmission organization or equivalent balancing authority and transmission operator has determined there are emergency conditions that could lead to a potential electrical blackout, such as unusually low frequency, equipment overload, capacity or energy deficiency, or unacceptable voltage level.” EPA received two conflicting petitions relating to the 15 hr/year Emergency DR allowance, and therefore, EPA has been reconsidering this provision.5  On January 4, 2012, EPA published a proposed settlement agreement stating that by April 20, 2012, it will sign a notice of proposed rulemaking that includes a proposal to revise the RICE NESHAP and, for consistency, the two ICE NSPS to allow operation in an Emergency DR program for 60 hours per year or the minimum hours required by Independent System Operator tariff, whichever is less.  EPA also states that a final action on the rule will be signed by December 14, 2012.

NSPS and Demand Response Participation

Similar to the NESHAP standard, applicable stationary engine NSPS requirements are dependent on the engine’s use classification (emergency or non-emergency).  However, all demand response participation (i.e., both Emergency DR and Economic DR) is currently considered non-emergency use.  With the January 4, 2012 proposed settlement agreement indicating that EPA intends to modify the Emergency DR allowance in the NESHAP ZZZZ, EPA also has indicated that it intends to amend the NSPS engine standards such that the NSPS and NESHAP standards will be consistent.  It is anticipated that all Economic DR will remain classified as non-emergency use.

Recent Changes in Federal National Ambient Air Quality Standards (NAAQS) that may Further Impact Air Quality Regulations on Generators

Recently, EPA tightened two NAAQS that have the potential to impact engine demand response projects. These new NAAQS standards are:

  • NO2 1-Hour NAAQS of 100 ppb effective 4/12/10
  • SO2 1-Hour NAAQS of 75 ppb effective 8/23/10

As these standards are based on a 1-hour averaging time, the short, horizontal stacks typical of generator engines may make it difficult to meet these standards.  As such, states may implement additional requirements for engines in order to achieve or maintain attainment with the NAAQS.

As mentioned previously, diesel fired engines (CI ICE) are more commonly installed as emergency back-up generators.  For most CI ICE installed prior to 2011, the NSPS IIII emissions standards for emergency use vs. non-emergency use are the same.  Therefore, if a CI ICE installed prior to 2011 is NSPS-compliant, then it likely meets the non-emergency limitations required to participate in Economic or Emergency DR.  However, case-specific review of the federal rule applicability, as well as review of potential state and local requirements, is strongly recommended prior to enrolling in a DR program.  Beginning in 2011, CI ICE commonly installed as emergency back-up generators, will be subject to the more stringent Tier 4 standards if utilized in a DR program.

Although less common, natural gas engines or other stationary internal (SI ICE) are also utilized as emergency back-up generators.  However, the SI ICE standards in NSPS JJJJ are not identical for pre-2011 emergency and non-emergency engines.  Therefore, retrofit controls would likely be required to meet the more stringent standards for DR participation.  Retrofits of certain natural gas engines may be cost effective considering demand response financial incentives.

State and Local Requirements

State and local air quality agencies also establish additional requirements for air emissions sources like engines.  Most commonly, these are categorical emissions standards as well as permitting requirements.

In order to achieve and maintain the federal National Ambient Air Quality Standards (NAAQS), states must implement Reasonably Available Control Technology (RACT) for stationary sources.  States may develop case-by-case RACT permitting requirements and, in some cases, state rules with presumptive RACT emissions standards for certain source categories (such as stationary internal combustion engines).  Emergency generators are often exempt from state NOx RACT programs that are applicable to non-emergency engines.  Therefore, enrolling an emergency generator in Economic DR may result in more stringent state-specific emissions limitations.  It should also be noted that a state’s definition of emergency use can differ from the federal definition, and therefore, must be evaluated to determine applicability of state rules.

State and local permitting requirements vary greatly depending on a number of factors.  The type and size of engine may qualify the unit for a permitting exemption.  Caution should be exercised with permitting exemptions as use type (emergency vs non-emergency) may also be a factor.  States may consider enrolling in a DR program a modification to the source, thereby triggering permitting and/or the implementation of best available technology requirements.  It should be noted that many states/localities allow emergency use engines to calculate the source’s potential to emit (PTE) based on 500 hours per year of operation while non-emergency engines would be required to base PTE on 8,760 hours per year.  Depending on the emissions levels from the engine and the facility, this change in PTE basis may trigger the need for a state permitting action such as taking a synthetic minor limit to avoid major source federal permitting.

In summary, enrolling in an Economic DR program will likely require permitting action and could trigger more stringent standards.  While several states include Emergency DR under emergency use provisions, a review of state and local regulations and emergency use must be conducted to determine applicability and ensure compliance.

Common Available Emission Control Technologies and Retrofit Costs

Table 1 identifies a few of the retrofit emissions control technologies that can be considered should DR participation require compliance with more stringent emissions standards.  Tier 4 engines are available for installation beginning early 2012; therefore, replacing older engines with new Tier 4 compliant units, may also be an economically feasible option for participating in DR.

When considering retrofit feassibility, some older engines such as pre-Tier units and poorly maintained engines may not be good candidates for control technology due to higher uncontrolled emissions rates.  Additionally, SCR may not be available for smaller engines (<200 hp) and also may not be cost effective for limited demand response participation.  In most cases where retrofit is required, emissions testing must also be conducted to demonstrate compliance with emissions standards.  However, due to the variation in testing costs, this additional cost is not reflected in the Table 1.


The use of on-site electricity generation as an element of a DR program is a viable solution to meet peak demand requirements; however, air regulatory and permitting requirements can be challenging.  Regulatory requirements for converting an existing emergency generator to DR use could range from no action required to installation and permitting of retrofit controls.  A case-by-case review of certain engine parameters relative to the federal, state, and local standards is necessary to ensure compliance.  Key parameters that should be considered include:

  • Participation in Emergency DR or Economic DR program
  • Location of site (attainment or non-attainment area)
  • Type of site (major or area source of HAPs; industrial, commercial, or institutional)
  • Existing permit status of generator
  • Size of generator and manufacture/installation dates of engine
  • Cost of retrofit emissions control or the cost of a new engine compared to the financial incentives of DR participation

1 Definition of Demand Response obtained from the FERC website at
2 On December 30, 2011, the U.S. Court of Appeals in Washington stayed CSAPR.  Therefore, the Clean Air Interstate Rule (CAIR) is still in effect.  Utilities generally have CAIR compliance plans in place.
3 The commencement of construction is the date that the owner/operator enters into a contractual agreement to install the engine on-site at their facility.  A change in ownership of an existing RICE does not make it new or reconstructed.  Reconstruction means the replacement of engine components to such extent that the fixed capital cost of the new components exceeds 50% of the fixed capital cost for a new engine and it is technologically and economically feasible to meet the applicable NSPS or NESHAP standards upon reconstruction.
4 It should be noted that engines that are >500 HP, located at a major source, and installed prior to June 12, 2006 will not have the allowance for 60 hours/year of emergency demand response.
5 75 FR 75937, December 7, 2010.