lable at ScienceDirect

Energy 35 (2010) 1553–1560

Contents lists avai

Energy

journal homepage: www.elsevier .com/locate/energy

Evolution and current status of demand response (DR) in electricity markets:Insights from PJM and NYISO

Rahul Walawalkar a,*, Stephen Fernands a, Netra Thakur a, Konda Reddy Chevva b

a Customized Energy Solutions Ltd., 1528 Walnut St, 22nd Fl, Philadelphia, PA 19102, USAb United Technologies Research Center, 411 Silver lane, E. Hartford, CT 06108, USA

a r t i c l e i n f o

Article history:Received 7 May 2009Received in revised form15 September 2009Accepted 15 September 2009Available online 20 February 2010

Keywords:Demand Response programsElectricity marketsPJMNYISO

* Corresponding author. Tel.: þ1 215 875 9440; faxE-mail address: rahul@ces-ltd.com (R. Walawalkar

0360-5442/$ – see front matter � 2009 Elsevier Ltd.doi:10.1016/j.energy.2009.09.017

a b s t r a c t

In electricity markets, traditional demand side management programs are slowly getting replaced withdemand response (DR) programs. These programs have evolved since the early pilot programs launchedin late 1990s. With the changes in market rules the opportunities have generally increased for DR forparticipating in emergency, economic and ancillary service programs. In recent times, various regulatorshave suggested that DR can also be used as a solution to meet supply – demand fluctuations in scenarioswith significant penetration of variable renewable sources in grid. This paper provides an overview of theevolution of the DR programs in PJM and NYISO markets as well as analyzes current opportunities.Although DR participation has grown, most of the current participation is in the reliability programs,which are designed to provide load curtailment during peak days. This suggests that there is a significantgap between perception of ability of DR to mitigate variability of renewables and reality of currentparticipation. DR in future can be scaled to play a more dynamic role in electricity markets, but thatwould require changes both on technology as well as policy front. Advances in building technologies andenergy storage combined with appropriate price signals can lead to enhanced DR participation.

� 2009 Elsevier Ltd. All rights reserved.

1. Introduction

When electric demand is at or near its peak level, less efficient orhigher cost generating units must be utilized to meet the higherpeak demand. In some cases, electricity prices in wholesale marketscould fluctuate from less than 5 cents per kWh to as much as 30cents per kWh on a significant number of days per year. Duringcapacity shortages, prices could increase to 50 cents per kWh orhigher for a few hours, reflecting the price signals that are requiredto match available supply to meet the demand. Under thesecircumstances, even a small reduction in demand through demandresponse (DR) programs can result in an appreciable reduction insystem marginal costs of production. In competitive electricitymarkets, where the marginal generating unit determines marketclearing price for all load, a drop in wholesale peak prices alsomeans that non-participants in demand response also share in thebenefits, as prices for everyone are held in check. These peak costs,although short in duration, add to the average cost per kWh to theconsumer and hence raise the average cost of a kWh of electricity.

: þ1 215 875 9490.).

All rights reserved.

The introduction of DR into constrained electricity networks cansignificantly reduce volatility in wholesale electricity prices and canpotentially act as a check against the exercise of market power bygenerators [1–4]. DR is also valuable as a tool to improve reliabilityof the grid [5,6], as well as increasing available transfer capacity ontransmission grid [7,8]. Recent research has also indicated thathistorically low participation in time-differentiated pricingprograms, as well as the low short-run price elasticity of demand,can result in potentially large social welfare losses in deregulatedmarkets. The welfare losses from low demand response levels couldbe significantly reduced by introducing administered DR programsin concert with centralized energy spot markets. [9] Studies havealso identified the need for advanced metering infrastructure (AMI)and building automation controls for enabling the potential of DRand energy efficiency [10–12].

In last decade, various research groups have tried to quantify thesocial benefits of DR in US markets. [13–15] A 2001 study byMcKinsey & Company [13] estimates that, $10–15 billion in annualbenefits can be achieved from participation of all customers indynamic pricing programs on a wide scale across U.S., with themajority of the potential, contrary to conventional wisdom, fromresidential sector DR efforts. The study estimated that the infra-structure needed for dynamic pricing can be brought to the massmarket, with payback periods of 5–6 years. Based on a review of

Table 1Summary of ISO/RTO initiated emergency DR events (source: PJM [18] & NYISO [19])

Year Emergency events in PJM Emergency events in NYISO

2000 2 (May 8 and 9)2001 4 (Jul 25, Aug 8–10) 4 (Aug 7–10)2002 3 (Jul 3, 29, 30) 4 (Apr 17 and 18, Jul 30 and Aug 14)2003 None 2 (Aug 15 and 16)2004 None None2005 2 (Jul 27, Aug 4) 1 (Jul 27)2006 2 (Aug 2, 3) 5 (Jul 17 and 18, Aug 1–3)2007 1 (Aug 8) 2 (Jul 19 and Aug 3)

R. Walawalkar et al. / Energy 35 (2010) 1553–15601554

current utility programs, Electric Power Research Institute (EPRI)[15] estimated that DR has the potential to reduce current U.S. peakdemand by 45,000 MW. The U.S. Federal Energy RegulatoryCommission (FERC) [16] released a cost-benefit analysis in 2002that showed a $60 billion savings over the next 20 years if DR isincorporated into RTO market design and operations.

2. Evolution of DR programs in PJM and NYISO

The ability of customers to respond to prices and reduceconsumption during periods of system shortage has been a criticalcomponent of both the PJM and NYISO electricity markets sincetheir start in 1997 and 1999 respectively. DR programs are designedto encourage consumers to modify their electric demand level andpattern of electricity usage. DR refers only to energy and load-shapemodifying activities undertaken in response to economic or reli-ability signals provided by utilities or ISOs and not to load-shapechanges arising from any normal operation. The Demand Responseand Smart Grid Coalition (DRSG) defines DR as the reduction ofcustomer energy usage at times of peak usage in order to helpaddress system reliability, reflect market conditions and pricing,and support infrastructure optimization or deferral. Demandresponse programs may include dynamic pricing/tariffs, price-responsive demand bidding, contractually obligated and voluntarycurtailment, and direct load control/cycling. Based on the type ofsignal used to activate the DR program, these programs can becategorized as either Emergency (or Reliability based) DR programsor Economic (Price based) DR programs or Demand Side AncillaryService programs [17]. The emergency DR programs aim to providecost-effective capacity resources to help avoid system outages incase of severe grid stress. On the other hand economic DR programsare developed to exert a downward pressure on electricity prices,by allowing demand side participation in electricity markets.Demand Side Ancillary Service programs allow DR to participate inancillary service markets such as frequency regulation and oper-ating reserves. Until recently some of the energy efficiency and loadshaping programs, that were part of traditional DSM initiatives,were not considered as DR. As explained later in this paper, PJMintroduced a new program in 2008–09, that provides capacitycredits to qualified energy efficiency projects as part of DR program.

The PJM and NYISO markets have separate energy, capacity andancillary services markets. Initially, both PJM and NYISO hadmechanisms for inclusion of DR programs in the capacity marketsthrough Emergency DR programs based on reliability criteria. Thiswas accomplished through reducing a Load Serving Entity’s (LSE)capacity obligation but limited integration into the energy markets.Partly in response to the very high price spikes experienced in 1998and 1999 various stakeholders realized that there was a benefit toincrease the ability of customers to respond to higher prices andreduce consumption. Since most customers at that time were onfixed pricing they did not have a direct incentive to reduceconsumption during high priced periods. Additionally there was nocapability to put in differing bidding parameters (such as theminimum commitment period for a load to reduce). Other issuesincluded limited availability of interval metering required formonitoring and billing customers based on their actual usage.

Initially inclusion of DR in PJM’s capacity markets was donethrough the Active Load Management (ALM) program. Thisprogram required customers, at that time typically through theirLSE, to commit prior to the summer period (June 1–September 15)that they could reduce their power consumption during at least 10days for a period of up to 6 h per day during the summer period. Inexchange the customer (or their LSE) would receive a capacitycredit for the entire year. The NYISO program, called Special CaseResources, was similar in that it reduced LSE’s capacity obligation

but unlike PJM included a separate summer and winter season aswell as testing requirements on participants. In both the PJM andNYISO capacity programs, the response of the participatingcustomers was mandatory and there were various penalties asso-ciated with non-compliance. The types of DR enrolled in theseprograms included residential load control devices (water heaters/air conditioners), commercial/industrial load reduction, and behindthe meter generation. In practice these programs were calledinfrequently with 0–5 events per year being called as shown inTable 1.

Capacity prices in the first few years of the markets were rela-tively high and were the primary source of overall revenue paid todemand side response resources. However, as capacity marketsstarted to go down in subsequent years and energy prices started torise, there was a move to integrate DR resources more closely intothe operation of the energy markets. For example, in PJM capacityprices were $34,799/MW-year in 2001 and fell to $2091/MW-yearby 2006. Since then the introduction of locational capacity marketand demand curve for capacity under Reliability Pricing Mecha-nism (RPM) has reversed the trend, particularly in capacity con-strained zones, and capacity prices varied between $35,000 and$86,000/MW-year during 2009–2010 delivery year.

While many LSEs used the ability of their customers to reduceconsumption during peak times for energy purposes (most oftenthrough interruptible rates), there was not an easy way to integratethese customers into the markets. In 2001 both PJM and NYISOstarted to develop mechanisms to allow customers to participate inthe energy markets either directly through a Curtailment ServiceProvider (CSP) or through the customer’s LSE. For a period of timethe PJM and NYISO programs leapfrogged each other with onemarket rolling out a component of DR and the other adopting thatand building off of it. The first add-on was an emergency energyprogram that both NYISO and PJM added allowing customers to getpaid an energy payment if they would voluntarily reduceconsumption during periods of emergency. These resources werecalled on very rarely and there was much debate about whether ornot they should set price in energy market. NYISO opted to havethem set the market clearing price and PJM chose not to.

In the NYISO the next DR market to be developed was the dayahead market with customers able to bid into the day aheadmarket in a similar manner to generators and through thisprocess set price and be dispatched by the NYISO. In PJM both theday ahead and real time markets were opened up to DRresources. PJM initially promoted the participation in real timeDR program as a voluntary effort, where customers did not faceany penalties for non-compliance. It was initially believed thatnew customers will use the real time DR program to get familiarwith the markets and then will gradually start participating inthe Day Ahead DR program, where participants commit tomandatory load curtailment targets if their bid is accepted in theday ahead energy market. Even today, in PJM most of the DRparticipation is in the Real Time DR program, and very fewcustomers participate in Day Ahead DR program.

Fig. 1. NYISO DR registration in MWs during 2001–2008 (source: NYISO, 2009 [21]).

R. Walawalkar et al. / Energy 35 (2010) 1553–1560 1555

In both markets one of the early questions was measurement ofdemand response. Since the compliance of emergency DRprograms were measured against the customers’ coincident peakdemand, verification was much more straight forward than in theeconomic DR programs where various factors could affect quantityof load curtailment. The compliance verification procedures havevaried over the time and have included similar day analysis usinga Customer Base Line (CBL), short term load drop, separate gener-ation metering, and statistical analysis.

The latest steps in the evolution of DR in these markets, includeopening up of ancillary service markets for DR and inclusion ofenergy efficiency as a capacity resource. PJM started allowing DRresources to participate in ancillary services markets in 2006. In2008, FERC issued Order No. 719 which adopted additionalmeasures to improve the operation of organized wholesale electricmarkets in the area of DR to further eliminate barriers andencourage the use of market prices to elicit DR. In response, NYISOalso opened the ancillary service markets for DR in 2009. PJM hasrecently taken the next step by allowing energy efficiency projectsto start receiving capacity credits for up to 4 years.

3. Current status of demand response programs in PJMand NYISO

With the expansion of DR programs in PJM and NYISO,customers with demand response capabilities now have theopportunity to get paid by the ISO similar to an energy generator,making it a more level playing field. End use customers canparticipate in these DR programs by using either distributedgenerators or energy management control strategies to reducetheir load in response to a price or emergency signal.

NYISO: The NYISO currently operates five demand responseprograms [20,21].

� Reliability based DR programso Emergency DR Program (EDRP): this is a voluntary program

where participants are paid the higher of $500/MWh or thereal time LMP for responding during system emergency.

o Special Case Resource Program (SCR): this program paysparticipants higher of their strike price (up to $500/MWh)or the real time LMP for mandatory response to emergencyevents. These resources can also sell capacity in the capacitymarket.

o Targeted Demand Response Program (TDRP): this programwas initiated in July 2007 to pay EDRP and SCR resourceshigher of $500/MWh or the real time LMP to respond tolocal reliability events within a particular zone. This avoidsneed to activate emergency events for entire zone toaddress local reliability concerns.

� Economic DR program:o Day Ahead DR Program (DADRP): DADRP allows customers

to submit bids in day ahead energy market for curtailingload above a certain bid floor price. The bid floor price wasincreased in 2004 to $75 from original value of $50. Customermust respond if their bid is cleared in the day ahead marketand curtailment cannot be achieved with use of backupgenerators. Failure to curtail results in a penalty defined by theMW curtailment shortfall multiplied by the greater of thecorresponding day ahead or real time market price.

� Ancillary services:o Demand Side Ancillary Service Program (DSASP): DSASP was

initiated in 2009 and allows DR to provide three ancillaryservices to NYISO markets. These include regulation,synchronous reserve and non-synchronous reserve.

Fig. 1 shows that over the years customers have preferred theSCR program which is most lucrative due to the locational capacitymarket revenues. Participation in the EDRP has gradually decreasedsince 2003, when the EDRP and SCR program participation wasmade mutually exclusive. The figure also shows that participationin the DADRP program has not changed significantly over the years,and suggests that NYISO is not able to attract more customers toparticipate in the economic DR program in recent years [21].

PJM: The PJM currently operates seven DR programs [22–24].

� Reliability based DR programso Emergency DR Program: similar to the NYISO program, this

is a voluntary program for reliability that offers energypayments to customers that reduce load during a systememergency. The payments are the higher of $500/MWh orthe zonal LMP for the hour. There is no penalty for non-compliance, and this program is rarely utilized by PJM (onlyfive times in past 3 years).

o Interruptible Load for Reliability (ILR): this program is similarto the NYISO SCR program and allows ILR to receive capacitypayments for load reduction achieved during systememergency. Load curtailment is mandatory for up to 10events each year, lasting up to 6 h per event. To encouragehigher participation of DR in capacity markets, ILRresources are allowed to register by March each year forupcoming delivery year (May–April). During 2008–2009,ILR accounted for 3489 MW out of a total of 4497 MWregistered under emergency DR. Last year FERC ruled infavor of eliminating the ILR program option to eliminate thefavorable treatment of DR under RPM. Thus 2011–2012 isthe last delivery year for ILR participation.

o Demand Resource (DR): Demand Resource is also eligible toreceive capacity revenues through PJM’s Reliability PricingModel (RPM). This resource has to participate in the forwardcapacity auction conducted by PJM 3 years before the deliveryyear along with other generation resources. So far majority ofthe DR resources had opted for ILR option to participate incapacity markets. Since DR will be the only option availablefrom 2012 to 2013, all DR resources interested in receivingcapacity credits in that year need to register as DR in May2009. Some of the current ILR participants may find it difficultto accept the financial risk of penalties by committingresources 3 year before the delivery year. This may reducetotal amount of DR available as a capacity resource for PJM.

Fig. 2. PJM DR program registration (2006–2008) [26,27,30].

Table 2Summary comparison of NYISO and PJM

NYISO PJM

Population Served 19.2 Million 51 MillionStates NY DE, IL, IN, KY, MD, MI, NC, NJ,

OH, PA, TN, VA, WV and DCPeak load 33.9 GW 144.6 GWTypes of DR

programsoffered

Economic (DADRP),Emergency (EDRP, SCR,TDRP), AncillaryServices (DSASP)

Economic (DADRP, RTDRP),Emergency (EDRP, ILR, DR,EE), Ancillary Services

Minimum size EDRP/SCR/TDRP:100 kWDADRP/DSASP: 1 MW

100 kW (for all)

Registeredemergency DR

1774 MW (SCRþ EDRP) 4497 MW (ILRþDR)

Registeredeconomic DR

320 MW 3290 MW

Adapted from Walawalkar et al. [31], FERC [32], and ISO websites.

R. Walawalkar et al. / Energy 35 (2010) 1553–15601556

o Energy Efficiency Resource (EE): in 2009, PJM started allow-ing energy efficiency resource to receive capacity credit forup to 4 consecutive years. An EE Resource is a project thatinvolves the installation of more efficient devices/equip-ment, or the implementation of more efficient processes/systems, exceeding then-current building codes, appliancestandards, or other relevant standards, at the time ofinstallation. Similar to Demand Resource, an EE resourcealso has to participate in the forward capacity auctionconducted by PJM 3 years before the delivery year. Thenominated EE value is the expected average demand (MW)reduction during the hours between 2 p.m. and 6 p.m.during all days from June 1 through August 31 (PJM, 2009).

� Economic DR Program:

Under this program PJM pays the customer the differencebetween the LMP and the generation and transmission (G&T)components of the customer’s bill. PJM offers this economic DRprogram in both its day ahead and real time markets.

o Day Ahead Demand Response Program (DADRP): this is a manda-tory program, where participant submits bids in day aheadenergy market and faces penalty for any non-compliance.

o Real Time Demand Response Program (RTDRP): RTDRP isa voluntary program, where customer needs to notify PJM ofintent to curtail load at least 1 h before load reduction isperformed.

Before January 2008, PJM also included an incentive paymentfor economic DR participants when they responded above a strikeprice of $75/MWh (similar to NYISO). The incentive paymentequaled the G&T component, and thus till 2007, DR participantswere eligible to receive full LMP value for curtailment during hourswhen LMP was above $75/MWh as is the case in NYISO. FERC [25]upheld the expiration of the incentive payments in an order underDocket EL08-12-000, issued on 31 December 2007.

� Ancillary Service DR Program:

In 2006, PJM started allowing DR to provide frequency regula-tion, synchronized reserve and day ahead scheduling reserves inancillary service market. DR resources are required to bid intoancillary service markets and respond to any event similarly toa generator. As of 2008, there were no DR resources providingfrequency regulation in PJM. Although PJM has not released infor-mation about amount of DR providing synchronized reserves, theseresources received almost $5M in payments during both 2007 and2008 [26,27].

Emergency DR participation has increased more than four timesover past 3 years, particularly as a result of substantial increase incapacity revenues under the RPM capacity markets, as compared tohistorical capacity revenues. This can be seen in Fig. 2.

Table 2 provides a quick summary of current status of DRprograms in these electricity markets.

3.1. Challenges for economic demand response in PJM

With the impressive growth of DR in these markets as well asplans of implementing smart grid, some policy makers and marketparticipants are anticipating that DR will be able to play a muchbigger role in electricity markets in near future. Currently most ofthe electricity markets, including NYISO are anticipating a signifi-cant growth in penetration of renewable resources (particularly

wind) in the supply mix over next 3–5 years. Due to the variabilityof wind, the systems operators are concerned with reliability of thegrid as well as price volatility. During some recent discussions, DR isbeing proposed as one of the solutions that could balance thevariability in supply [28].

Although DR has proved to be an effective resource to meetreliability needs in both PJM and NYISO, the amount of DR as well asthe type of response desired to mitigate variability of large scalewind or solar is significantly different. Current DR participation inthese markets is clearly not sufficient to provide a viable solutionfor matching variability of resources like wind on a continuousbasis, especially in scenarios with 10% or higher penetration ofrenewables. As mentioned earlier, NYISO [21] has failed to attractany additional load curtailment in the DADRP program since 2003.On the other hand the registration in PJM’s economic DR programshas grown substantially over the years to 3290 MW in 2008 [26]. Atthe same time, a distinction must be made between loads that areregistered to participate in the PJM economic DR program, and theamount of load that actively participates in the market [29]. During2006, there was 1475 MW load registered under the economic DRprogram and an additional 1081 MW load registered under theemergency DR program [30]. However, during the summer of 2006when PJM registered it’s all time peak load of 144.6 GW, there wasonly 325 MW of DR cleared in the economic DR program [33]. Thistrend has continued in recent years and data released by PJM in2009 indicates that out of over 4800 sites registered in economic

Fig. 3. NPV of potential DR revenues over 5 years with and without incentive (source: Walawalkar et al. [23]).

1 Statement of Terry Boston, President and CEO, on behalf of the PJM Board ofManagers is available at http://pjm.com/w/media/about-pjm/newsroom/2009-releases/20090626-pjm-board-statement-regarding-dr-in-pjm-markets.ashx.

R. Walawalkar et al. / Energy 35 (2010) 1553–1560 1557

DR programs, maximum of 301 sites actually curtailed load underDADRP/RTDRP program in any month during 2007–2008 [26,27].This situation needs to change dramatically by encouraging moreactive participation of DR in energy and ancillary service markets aswell as development of new DR programs that will provideappropriate price signal for customers to mitigate fluctuations inrenewables from hour to hour.

One of the issues facing economic DR participants in PJM is theelimination of incentive for participation in economic DR programin December 2007 [23]. As a result of the expiration of incentivesfor DADRP and RTDRP, instead of receiving full LMP for loadcurtailment, participants now receive payments from PJM based ondifference between the LMP and the generation and transmission(G&T) components of the customer’s bill. Thus DR participants mayhave increased their strike price so that the marginal paymentsfrom DR program participation are equalized with and without theincentive payment. For instance, customers with a G&T rate of $50/MWh may change their strike price from $75/MWh to $125/MWhto retain the same payment from PJM for curtailing load.

The total payoff to any individual customer from economic DRparticipation depends not only on the strike price and incentivestructure, but also the distribution of market prices that can changefrom year to year. Fig. 3 shows the results of a simulation conductedto project effect of removal of incentive on revenues for economicDR participants in PJM [23]. We have incorporated uncertainty dueto fluctuations in energy prices from year to year into our analysisby performing a Monte Carlo simulation on the expected annual DRrevenue stream, using energy market data from PJM during 2004–2007 [34].

We modeled annual revenues based on participant’s strike pri-ces, with and without the DR market incentives. For each year t andstrike price k, we assumed that annual DR revenues (p) followa triangular distribution with the minimum value equal to the sumof hourly revenues in 2004 (the lowest revenue year in our sample),the maximum equal to the sum in 2005 (the highest), and the mostlikely value equal to the average of the four years. We generated1000 realizations of the discounted present value of expectedannual revenues over a five year time horizon, assuming a customerwith an internal discount rate of 10%; we did this for a $75 strike

price with the incentive, for a $75 strike price without the incentiveand for a $125 strike price without the incentive.

The simulation indicates that before expiration of incentives,any economic DR resource offering 1 MW load curtailment at $75/MWh would receive a discounted gross revenue stream of $610,000over five years with a 50% probability. On the other hand, withoutthe incentive payment and customer adjusting her strike price to$125/MWh (to receive the DR payment of $75/MWh), the NPVwould fall by roughly a factor of five, to $107,000 as shown in Fig. 3.

The change in the potential DR revenue in economic DRprogram due to change in the incentive structure can also be seenin the data released by PJM as shown in Fig. 4. The figure indicatesthat although overall DR revenues for all participants have grownsubstantially over past 3 years, revenue for economic DR partici-pation decreased from approximately $60M in 2007 to $20M in2008. As a result although overall participation in the DR isincreasing over the years considering the reliability basedprograms, increasing active participation in the price-responsiveDR will be a challenge.

PJM Board of Directors acknowledged this in a press release on26 June 2009, which announced that PJM will reintroduce incentivepayments for demand response for the top 9% of the hours from theprevious year.1

4. Opportunities for growth

Currently the majority of DR program participation is throughuse of backup generators or use of curtailable loads. The vastpotential of existing building EMS systems and energy manage-ment strategies is still untapped, not to mention future possibilitiesas home automation and smart appliances become standardizedalong with deployment of smart grid infrastructure as shown inFig. 5. Also most of the energy efficiency project developers are not

Fig. 4. PJM demand side response estimated revenues 2001–2008 (source: PJM [35]).

R. Walawalkar et al. / Energy 35 (2010) 1553–15601558

familiar with the electricity markets and the newly developedoption of receiving capacity revenues for EE resources.

In a competitive market, new generating capacity will not beadded until prices rise sufficiently above the cost of new facilities.The existing energy efficiency and control technologies, however,can be a great tool in expanding DR program participation. Table 3shows a sample of some of the control strategies that can be usedby different types of customers for participating in various DRprograms.

Ongoing advances in the research focused on develop technol-ogies, tools and standards to make commercial and residentialbuilding systems more energy efficient and productive can alsofacilitate DR participation. Some of key areas of research related tohigh performance buildings include new building and equipmentstandards, integrated building systems, and solid-state lighting.Besides making existing buildings energy efficient, there is also anincreased effort to design new net zero energy buildings by inte-grating renewable technologies like solar, geothermal, wind,biomass and fuel-cell and hydrogen technology.

Fig. 5. Components of a Demand Response Progr

We briefly discuss some of the emerging technologies andstandards that hold a lot of promise for enabling DR in residentialand commercial segment.

� ZigBee enabled DR systems: demand response systems formonitoring energy usage in homes are amongst the mostpromising of new technologies. The technology that is drivinga new wave of home automation is Zigbee, a low-powerwireless networking standard designed for controlling andmonitoring applications. On one hand, utility companies areincreasingly evaluating Advanced Metering Infrastructure(AMI) networks to provide two-way communication betweenthe home and utilities via wireless smart meters. On the otherhand, wireless Home Area Networks (HANs) are being adoptedby home-owners to better gain whole-house entertainmentcontrol. Zigbee is the wireless technology that helps connectAMI networks and HANs. This can allow home-owners andutilities to communicate in real time and manage energyconsumption.

am implementation (Walawalkar et al. [31]).

Table 3Control strategies and applicable DR programs for different customer types

Customertype

Equipment/buildingcomponent

Controlstrategy

DR programs

Emergency(capacity)

Economic(energy)

Ancillary(Reg &Res)

Residential Airconditioners

Cycling/forceddemandshedding

U U U

Waterheaters

Cycling U U U

Pool pumps Cycling U U U

Electricstove

Scheduling U

Commercial Chillers Demand limitingduring on peakperiod

U U

ChillersHVAC

Pre-cool bldgover night-storage

U

DX Forceddemandscheduling

U U

Refrigerator/freezer

Prioritizeddemandshedding

U

Lighting Scheduled on/off U

Lighting Scheduleddimming ofselected circuits

U

Industrial Chillers Demand limitingon time schedule

U

Electricfurnace

Demand limitingthrough heatstages

U U

ElectricfurnaceVSDs

Curtail (duringpeak period)

U U U

Limit output onscheduled basis

U

Well pumps Defer duringpeak

U U

Productionequipment

Prioritizeddemand onselected units

U

Restaurants/shoppingmalls

HVAC Chillers –demand limitingduring peak

U

DXcompressor

Forced demandshedding ofmultiple units

U U

Refrigerator/freezer

Prioritizeddemandshedding

U

ElectricSToves

Scheduled pre-cooking

U

Adapted from Walawalkar et al. [31].

R. Walawalkar et al. / Energy 35 (2010) 1553–1560 1559

� In-Home Energy Use Displays: in-home energy use displaysprovide real time feedback to the occupants about the totalenergy usage in the house. This information can be displayedthrough existing home PCs using applications such as GooglePowerMeter� or Microsoft Hohm�. Google PowerMeter� canreceive information from utility smart meters and energymanagement devices and provides customers with access totheir home electricity consumption right on their personaliGoogle homepage. On the other hand, new products are beingdeveloped that can be used to signal the need for demandresponse without consumers using their computers. In Cal-ifornia, PG&E has introduced a ‘‘Demand Response Orb’’ toinform customers of Critical Peak Pricing periods and/oremergency events. The projected energy savings from the useof such displays ranges from 4% to 15%.

� New Building Standards: building codes have been usedfor nearly three decades and are a cost-effective strategy toovercome barriers to energy efficiency in buildings. Mostresidential buildings adopt the International Energy Conser-vation Code (IECC) whereas most commercial building energycodes are based on ASHRAE/IESNA Standard 90.1. According toCalifornia Energy Commission, building standards have helpedsave businesses and residents in California more than $15.8billion in electricity and natural gas costs since 1975. Now withthe availability of capacity revenues for EE resources from elec-tricity markets, businesses have an added incentive for choosingnewer standards that go beyond current standards. The vision forthe future is that buildings are ‘‘DR enabled’’ and major appli-ances are ‘‘DR ready’’ from the factory. Building standards thatincorporate controllable thermostats in residential and priceserver interface in commercial buildings will greatly help DR. Onthe appliance side, DR will benefit from standards that includeembedded controls for HVAC and other systems.� Energy storage technologies: another emerging technology area

that can provide significant boost to DR capability in electricitymarkets is electric energy storage (EES). Currently approxi-mately 2.5% of the total electric power delivered in the UnitedStates passes through energy storage, largely pumped hydro-electric. The percentages are significantly larger in Europe andJapan, at 10% and 15%, respectively [36]. In recent years, therehas been tremendous advances made in various EES technol-ogies, particularly in areas of advanced batteries (suchas lithium ion, flow batteries and sodium sulfur), flywheeltechnologies that can provide frequency regulation as well asmodular designs for above ground Compressed Air EnergyStorage (CAES). With successful adaption of some of thesetechnologies in commercial and industrial applications, marketparticipants investing in EES as a behind the meter resource,can use it as DR resource.

5. Conclusions

Electricity markets have made significant progress over pastdecade in integrating DR into electricity market design. PJM andNYISO have been on the forefront of such developments, andcurrently offer a wide range of programs that allow DR to participatein these markets. In general all DR programs rely on end usersdeliberately altering use of equipment and systems, which generallymeans lifestyle or comfort changes, or changes in operating proce-dures. Such changes would be acceptable to end users only if theconsumer has a stake in the process either through financialcompensation or through improved reliability of power supply. Alsoit is important to realize that all DR programs are not equal. Differenttypes of programs have specific objectives, and demand varyinglevel of commitment from DR resources with different payoffs.

Current market based DR programs are very successful inattracting participation in emergency or reliability based programs,which require relatively modest commitments from end users. Ifwe expect DR resources to scale up to enable greater level ofrenewable integration, then we need to start evaluating DR tech-nologies that are suitable for participating every day. We also needto evaluate if current programs are the right programs to provideincentives to customers for such role. For example, Economic DRprograms will not provide sufficient revenues for customers torespond during off peak hours, whereas emergency programs aredesigned to provide response only during peak hours. On the otherhand the wind energy is generally expected to have the largestshare of the supply mix during night or early morning hours. Wewill need DR technologies such as EES that can respond in both

R. Walawalkar et al. / Energy 35 (2010) 1553–15601560

direction (absorb power as well as provide fill up power), and newDR programs that provide appropriate financial incentives forcustomers to participate.

We are witnessing great advances in technology that can helpDR to scale up substantially, but technology alone is not sufficient.The process of evolution of DR programs in electricity markets isnot complete, and with changing needs of the market, stakeholdersin NYISO and PJM need to continue efforts for increasing DRparticipation.

Acknowledgements

We thank Dr. Jay Apt, Dr. Lester Lave, Dr. Rahul Tongia, Dr.Granger Morgan (Carnegie Mellon University), Dr. Bruce Colburn(EPS Capital Corp.) and Dr. Seth Blumsack (Pennsylvania StageUniversity) for useful comments and conversations. We acknowl-edge timely inputs from our colleagues Rick Mancini and RickGilkey at Customized Energy Solutions. We also acknowledgecontribution of the reviewers of this special issue, which helped usto identify areas that required further explanation.

References

[1] Electricity markets: consumers could benefit from demand programs, butchallenges remain (US-GAO-04-844), A report to Senate Committee onGovernmental Affairs. U.S. Government Accountability Office. Available from:,http://www.gao.gov/new.items/d04844.pdf; 2004.

[2] Violette D, Freeman R, Neil C, DRR valuation and market analysis. Overview,a report for the International Energy Agency (IEA) DRR Task XIII, vol. I; 2006.Available from: http://www.demandresponsecommittee.org/id80.htm.

[3] Violette D, Freeman R, Neil C, DRR valuation and market analysis, Assessingthe DRR benefits and costs, a report for the International Energy Agency(IEA) DRR Task XIII, vol. II; 2006. Available from: http://www.demandresponsecommittee.org/id81.htm.

[4] Rassenti S, Smith V, Wilson B. Demand-side bidding will reduce the level andvolatility of electricity prices. Independent Review(3):441–5. Available from:http://www.independent.org/pdf/tir/tir_06_3_smith.pdf, 2002;6.

[5] Goel L, Wu Q, Wang P. Reliability enhancement of a deregulated power systemconsidering demand response. IEEE Power Engineering Conference Issue2005;2:934–8.

[6] Azami R, Fard A. Impact of demand response programs on system and nodalreliability of a deregulated power system. Sustainable Energy Technologies,ICSET 2008;2008:1262–6.

[7] Shayesteh E, Yousefi A, Moghaddam P. ATC enhancement using emergencydemand response program. IEEE Power Systems Conference and Exposition2009;2009. PES ’09.

[8] Green R. Electricity transmission pricing: how much does it cost to get itwrong?. MIT Center for Energy and Environmental Policy Research; 2004.MIT-CEEPR (Series); 04-020WP.

[9] Boisvert R, Neenan B, Social welfare implications of demand-responseprograms in competitive electricity markets, Lawrence Berkeley NationalLaboratories working paper LBNL-52530; 2003. Available from: http://eetd.lbl.gov/ea/EMS/reports/LBNL-52530.pdf.

[10] Lavy R, Herter K, Wilson J, Unlocking the potential for efficiency and demand-response through advanced metering, Lawrence Berkeley National Laboratoryworking paper; 2004. Available from: http://repositories.cdlib.org/lbnl/LBNL-55673.

[11] Piette M, Watson D, Motegi N, Bourassa N. Findings from the 2004 fullyautomated demand response tests in large facilities. Demand ResponseResearch Center; 2005. LBNL Report Number 58178.

[12] FERC. A national assessment of demand response potential. staff report.Federal Energy Regulatory Commission; June 2009.

[13] McKinsey & Company. The benefits of demand side management and dynamicpricing programs. Mckinsey and Company. Available from: http://republicans.

energycommerce.house.gov/107/hearings/06222001Hearing265/swofford.pdf;May 2001.

[14] Lovins A, Datta E, Feiler T, Rabago K, Swisher J, Lehmann A, et al. Small isprofitable: the hidden economic benefits of making electrical resources theright size. Rocky Mountain Institute; 2002.

[15] The Western States power crisis: imperatives and opportunities, EPRI whitepaper. EPRI. Available from: http://www.pserc.wisc.edu/ecow/get/publicatio/specialepr/gridreliab/westernstatessynthesi1.pdf; 2001.

[16] ICF Consulting. Economic assessment of RTO policy. FERC. Available from:http://www.ferc.gov/legal/maj-ord-reg/land-docs/rtostudy_final_0226.pdf;2002.

[17] PJM. A demand response roadmap in PJM symposium on demand response II.PJM Interconnection. Available from: www.pjm.com; 2008.

[18] PJM. Summary of PJM-initiated load management events. PJM Interconnec-tion. Available from: http://www.pjm.com/planning/res-adequacy/downloads/20070907-alm-history.pdf; Sept 2007.

[19] NYISO. Historic EDRP and SCR activation information. Nyiso. Available from:http://www.nyiso.com/public/webdocs/products/demand_response/general_info/event_history.pdf; 2008.

[20] NYISO. State of the market report 2008. New York ISO. Available from: www.nyiso.com; 2007.

[21] NYISO, Annual compliance report on demand side management andnew generation projects submitted to FERC; January 2009. Available from:http://www.nyiso.com/public/webdocs/documents/regulatory/filings/2009/01/DemandSideMgmtCompFiling_1_15_09.pdf.

[22] PJM, Demand response program information. Available from: http://www.pjm.com/markets-and-operations/demand-response.aspx [Information accessedon 1 May 2009].

[23] Walawalkar R, Blumsack S, Apt J, Fernands S. An economic welfare analysis ofDemand Response in PJM electricity market. The Energy Policy October2008;36(10).

[24] Brattle Group, 2007. Quantifying demand response benefits in PJM, A reportfor PJM Interconnection and Mid Atlantic Distributed Resource Initiative(MADRI). Available from: http://www.energetics.com/madri/pdfs/BrattleGroupReport.pdf.

[25] Docket EL08-12-000. Federal Energy Regulatory Commission (FERC); 2007.issued on 31 December 2007.

[26] O’Neil J. DSR activity report presented to PJM Demand Response SteeringCommittee. PJM 2009. Available from: http://www.pjm.com/committees-and-groups/committees/drsc.aspx; 2008.

[27] Gockley B. DSR activity report presented to PJM Demand Response SteeringCommittee. PJM 2009. Available from: http://www.pjm.com/committees-and-groups/committees/drsc.aspx; 2007.

[28] Stadler I. Power grid balancing of energy systems with high renewable energypenetration by demand response. Utilities Policy 2007;16(2):90–8.

[29] Hopper N, Goldman C, Bharvirkar R, Engel D. The summer of 2006: a mile-stone in the ongoing maturation of demand response. The Electricity JournalJune 2007;20(5):62–75.

[30] Kujawski D. DSR activity report presented to PJM Demand Response SteeringCommittee. PJM 2009. Available from: http://www.pjm.com/committees-and-groups/committees/drsc.aspx; 2006.

[31] Walawalkar R, Tongia R, Colburn B. Web-enabled metering and controls fordemand response. In: Capehart BL, Capehart LC, editors. Web based enterpriseenergy and building automation systems. Lilburn, Georgia: The FairmontPress, ISBN 0849382351; 2007. p. 299–314.

[32] FERC. Electric power markets: national overview Available from: http://www.ferc.gov/market-oversight/mkt-electric/overview.asp.

[33] Covino S, PJM economic load response: summer 2006 potential and perfor-mance. A presentation to the Demand Side Response Working Group;November 2006. Available from: http://www.pjm.com/committees/working-groups/dsrwg/downloads/20061130-item-09-summer-2006-performance.pdf.

[34] PJM locational marginal pricing data. Available from: http://www.pjm.com/markets/jsp/lmp.jsp.

[35] PJM. PJM demand side response estimated revenue, Presented to PJMDemand Response Steering Committee; 2009. Available from: http://www.pjm.com/committees-and-groups/committees/w/media/committees-groups/committees/drsc/postings/demand-side-response-estimated-revenue.ashx.

[36] Walawalkar R, Apt J, Market analysis of emerging electric energy storagesystems, A report developed for Department of Energy (DOE) and NationalEnergy Technology Labs (NETL), DOE/NETL-2008/1330; July 2008.