# Attachments to Petition for Reconsideration

RIN 2060-AP36 EPA Docket No. OAR-2008-0708

Petitioners: CPower, Inc. EnergyConnect, Inc. EnerNOC, Inc. Innoventive Power, LLC 

# Attachments to Petition for Reconsideration

RIN 2060-AP36 

# EPA Docket No. OAR-2008-0708



# Petitioners: CPower, Inc. EnergyConnect, Inc. 

# EnerNOC, Inc. 

# Innoventive Power, LLC

### List of Attachments

1. Modeling Demand Response and Air Emissions in New England 2. North American Electric Reliability Council Standard EOP-002-2.1 - Capacity and Energy Emergencies 3. PJM Manual 13: Emergency Operations 4. PlM FERC Electric Tariff, Sixth Revised Volume No.1, PJM Emergency Load Response Program 5. PlM Reliability Assurance Agreement Among Load Serving Entities in the PJM Region Condition, Rate Schedule FERC No. 44 6. ERCOT Protocols, Section 5: Dispatch 7. ERCOT Protocols, Section 6: Ancillary Services 8. Emergency Operations for ERCOT, Chapter 25, Subchapter S 9. ISO New England, Inc., Transmission, Markets and Services TariffFERC Electric Tariff No.3, Appendix E 10. ISO New England Operating Procedure No.4, Action During a Capacity Deficiency 11. NYISO Emergency Operations Manual 15 12. NYISO: Called Events & Tests 13. PJM Zone Map 14. ISO New England 2011 Emergency DR Dispatch Zones 15. Comments on Proposed Rule, National Emission Standards for Hazardous Air Pollutants for Reciprocating IntemalCombustion Engines, Submitted by DRSP Coalition, May 29, 2009 16. EPA's Response to Public Comments 17. Letters from CPower and Innoventive Power to Ms. Melanie King, EPA, March 26 and May 21, 2010 18. How New England States Handle Emergency DR 19. How PJM States Handle Emergency DR 20. TCEQ Letter Regarding Use of Emergency Engines in ElLS 

## List of Attachments

1. Modeling Demand Response and Air Emissions in New England
2. North American Electric Reliabilty Council Standard EOP-002-2.l - Capacity and 

### Energy Emergencies
3. P JM Manual 13: Emergency Operations 

### 4. PJM FERC Electric Tariff, Sixth Revised Volume No.1, PJM Emergency Load 

### Response Program

5. P JM Reliability Assurance Agreement Among Load Serving Entities in the P JM Region 

### Condition, Rate Schedule FERC No. 44 

### 6. ERCOT Protocols, Section 5: Dispatch 

### 7. ERCOT Protocols, Section 6: Ancilar Services
8. Emergency Operations for ERCOT, Chapter 25, Subchapter S
9. iso New England, Inc., Transmission, Markets and Services TariffFERC Electric Tariff No.3, Appendix E
10. iso New England Operating Procedure No.4, Action During a Capacity Deficiency
1 1. NYISO Emergency Operations Manual 15 

### 12. NYISO: Called Events & Tests
13. PJM Zone Map
14. iso New England 2011 Emergency DR Dispatch Zones 

### 15. Comments on Proposed Rule, National Emission Standards for Hazardous Air Pollutants

for Reciprocating Internal Combustion Engines, Submitted by DRSP Coalition, May 29, 

### 2009
16. EPA's Response to Public Comments
17. Letters from CPower and Innoventive Power to Ms. Melane King, EPA, March 26 and

May 21, 2010 

### 18. How New England States Handle Emergency DR
19. How PJM States Handle Emergency DR

20. TCEQ Letter Regarding Use of 

### Emergency Engines in EILS

# Attachment 1

Modeling Demand Response and Air Emissions in New England (Synapse Energy Economics, Inc.) Attachment 1



# Modeling Demand Response and Air Emissions in 

# New England (Synapse Energy Economics, Inc.)

# SynQ!p~,e Energy Economics, Inc.



# Modeling Demand Response and Air Emissions in New England

Prepared by: Geoff Keith, Bruce Biewald, David White and Mike Drunsic Synapse Energy Economics 22 Pearl Street, Cambridge, MA 02139 www.synapse-energy.com 617-661-3248

Prepared for: U.S. Environmental Protection Agency


### August, 2003 Revised: September 4,2003 

# Synè!p~,e Energy Economics, Inc.



# Modeling Demand Response and Air 

# Emissions in New England

Prepared by: 

### Geoff Keith, Bruce Biewald, David White and Mike Drunsic 

### Synapse Energy Economics 22 Pearl Street, Cambridge, MA 02139 

## ww.synapse-energy.com 617-661-3248


### Prepared for: U.S. Environmental Protection Agency

August, 

## 2003 Revised: September 4,2003

## Table of Contents

Executive Summary ~ : 1 Results 2 1. Introduction 4 2. Inputs and Assumptions 5 2.1 The DR Program Modeled 6 2.2 Geographic Distribution of DR Capacity 7 2.3 Emission Rates 7 2.4 Energy Efficiency Programs 8 2.5 Operating Reserves Under Standard Market Design 8 3. Results 10 3.1 DR and Power Plant Operation 10 3.2 Air Emissions When DR is Used as Reserves 13 3.3 Emissions When DR is Not Used for Reserves 15 3.4 Largest Single-Day Impacts ofpR 18 3.5 The Impacts of DR versus Energy Efficiency 19 4. A Methodology for Assessing DR Events Retrospectively .•••••.•••.••••••.•••••••••••••••••• 22 Apendix A: The PROSyM/MuLTISYM Model ..............................................•......... 24



# Table of Contents

Executive Summary .................................................~..................:..................................... i 

### Results......................................................................................................................2
1. Introduction.................................................................................................................4 

### 2. Inputs and Assumptions ............................................................................................. 5 2.1 The DR Program Modeled................................................................................ 6

2.2 Geographic Distrbution of DR Capacity ......................................................... 7 

### 2.3 Emission Rates..................................................................................................7 2.4 Energy Effciency Programs ....... ..... ... .... ...... .... .... ...... ..... ......... ..... ...... ... .... ...... 8 2.5 Operating Reserves Under Stadard Market Design........................................ 8
3. Results ........................................................................................................................ 10 

### 3.1 DR and Power Plant Operation.......................................................................10 3.2 Air Emissions When DR is Used as Reserves................................................ 13 3.3 Emissions When DR is Not Used for Reserves.............................................. 15 3.4 Largest Single-Day Impacts ofpR................................................................. 18

3.5 The Impacts of 

### DR versus Energy Efficiency................................................ 19

4. A Methodology for Assessing DR Events Retrospectively.................................... 22 

### Apendix A: The PROSyM/LTISYM Model ........................................................ 24

## Executive Summary

In January 2003 Synapse began work to assess the potential emissions impacts of demand response (DR) and energy efficiency programs in New England. Synapse performed this work under subcontract to Eastern Research Group, funded by the U.S. EPA. EPA funded this project largely to inform the work of the New England Demand Response Initiative (NEDRI), a collaborative process designed to develop recommendations for expanding DR programs in New England. The key goals of the analysis were to: • Estimate the net emissions impacts of mature DR programs in New England under different assumptions, • Explore the impact of DR generating technology and fuel mix on net emissions, • Explore the extent to which additional DR capacity in New England could result in reduced air emissions from more efficient unit commitment, • Explore the impact of load shifting on net emissions, and • Compare the emissions impact of DR programs to those of energy efficiency programs. In addition to this work, EPA also requested that Synapse develop a methodology for estimating the emissions impacts of actual DR events retrospectively. The dispatch modeling portion of this analysis was performed with the PROSYMIMUL TISYM production costing model. A hypothetical near-term year in New England was modeled, using projected 2006 fuel prices and loads. In order to model a relatively capacity-constrained year (i.e., a year in which there was likely to be robust DR operation), a 20-percent system reserve margin was created by making minor adjustments to NEPOOL's projected plant in service in 2006. An economic DR program was modeled. This is a program in which DR resources bid into the day-ahead energy market along with other supply-side resources and are dispatched based on their bids, like supply-side resources. The DR program modeled included 500 MW of DR capability, with 60 percent assumed to be load response and 40 percent, generation. This ratio is based on data provided by ISO New England regarding recent (February 2003) enrollment in the New England economic DR program, (known then as the "Class 2" program). Scenarios were explored involving several different mixes of diesel- and gas-fired engines providing the generation portion of the DR. DR capacity was allocated to locational marginal pricing (LMP) zones based primarily on industrial electricity sales, with some capacity shifted from capacity-surplus zones to southwestern Connecticut, to reflect the tight capacity situation there. DR resources were modeled as bidding at five bid points: $100, $200, $300, $400 and $500 per MWh. This assumption is based on research performed in New York State on the cost of providing DR. Within a zone, equal amounts of DR were bid at each bid point, and generators bid a four-hour minimum up time. Sensitivity analyses were performed to determine the impact that load shifting has on total net emissions from DR.

Synapse Energy Economics - Title of Report Page 1 

# Executive Summary
In Janua 2003 Synapse began work to assess the potential emissions impacts of demand 

### response (DR) and energy efficiency progrms in New England. Synapse performed this 

### work under subcontract to Eastern Research Group, fuded by the U.S. EPA. EPA

fuded this project largely to inorm the work of the New England Demand Response 

### Initiative (NDRl), a collaborative process designed to develop recommendations for

expanding DR programs in New England. The key goals of the anlysis were to:
. Estimate the net emissions impacts of matue DR programs in New England 

### under different assumptions,

. Explore the impact of DR generating technology and fuel mix on net emissions,
. Explore the extent to which additional DR capacity in New England could result 

### in reduced air emissions from more effcient unt commitment,
. Explore the impact of load shiing on net emissions, and

. Compare the emissions impact of 

### DR progrs to those of energy effciency 

### progrms. In addition to this work, EPA also requeste that Synapse develop a methodology for estimating the emissions impacts of actual DR events retrospectively. 

### The dispatch modeling portion of this analysis was performed with the 

### PROSYM TISYM production costing modeL. A hypothetical nea-term year in New England was modeled using projected 2006 fuel pnces and loads. In order to model a relatively capacity-constrned year (Le., a year in which there was likely to be 

### robust DR operation), a 20-percent system reserve magin was created by makng minor adjustments to NEPOOL's projected plant in servce in 2006. An economic DR program was modeled. Ths is a progrm in which DR resources bid 

### into the day-ahead energy market along with other supply-side resources and are 

### dispatched based on their bids, lie supply-side resources. The DR program modeled

included 500 MW of DR capabilty, with 60 perct assumed to be load response and 40 percent, generation. Ths ratio is based on data provided by ISO New England regarding recent (Febru 2003) enrollment in the New England economic DR program, (kown then as the "Clas 2" progr). Scenanos were explored involving severl different
mixes of diesel- and gas-fied engies providig the generation porton of the DR. 

### DR capacity was allocated to locational margial pncing (LMP) zones based pnmly on industral electrcity sales, with some capacity shiftd from capacity-surlus zones to southwestern Connecticut, to reflect the tight capacity situation there. DR resources were 

### modeled as bidding at five bid points: $ 100, $200, $300, $400 and $500 per MW Th assuption is based on reseah performed in New York State on the cost of providing

DR. Within a zone, equa amounts of 

### DR were bid at each bid point, and generators bid a 

### four-hour minium up time. Sensitivity anlyses were performed to determe the impact that load shiftg has on tota net emssions from DR.

Synapse Energy Economics - Title of Report Page 1In addition to DR, the air impacts of two different energy efficiency programs were

explored: an energy-targeted program and a peak-targeted program. The energy-targeted program reduced peak demand by one percent and annual energy use by 0.75 percent. The peak-targeted program reduced peak demand by 1.2 percent and annual energy use by 0.50 percent. These numbers were developed based on a review of current efficiency program impacts in New England.


### Results • In the economic DR program modeled, the DR resources provided 3,361 MWhs of load relief during the summer: 1,451 MWhs of onsite generation and 1,910 MWhs of load response. This is over three times the amount of load relief provided by ISO New England's 2002 economic DR program (1,011 MWh). This level of DR activity is consistent with our goal of modeling a mature DR program in a moderately capacity constrained year. DR resources would operate more in an extremely constrained period, such as the California crisis of 2000-200 1. • Over 90 percent of the DR load relief occurs in southwestern Connecticut. Much of the 500-MW DR resource is never dispatched (including all of the capacity in Maine, New Hampshire and Rhode Island); however all of the DR capacity is used to meet operating reserve requirements during the summer if allowed to do so. • When the DR resource is used to meet reserve requirements, the result is more efficient unit commitment, reduced operation of oil- and gas-fired steam units and increased operation of combined-cycle units in New England. New England also imports more energy from neighboring control areas with the DR resource. The net impact of these dynamics is a potential reduction in criteria pollutant emissions. However, in order to realize the NOx and S02 reductions, mechanisms would have to be established to ensure that they were not lost through emissions trading. • Potential emission reductions in this scenario are largest in the summer months. Assuming no diesel generation in the DR program, summer NOx reductions could be as large as 41 tons (0.18 percent); S02 reductions could be 218 tons (0.3 percent), and C02 reductions could be 31,800 tons (0.13 percent). The impact of DR on mercury emissions is negligible; however there are small increases in several air toxics associated with internal combustion (IC) engine generators. I • This finding (potential emission reductions come from additional DR capacity used to meet reserve requirements) is specific to New England and should not be extrapolated to other control areas. Further, this finding is based on clearly identified assumptions about how the ISO currently commits generating units and meets reserve requirements. To the extent that these assumptions do not capture the full complexity of this process, this finding may need to be reevaluated. • Different assumptions about the mix of diesel- and gas-fired generation in the DR program lead to small but significant impacts on the emissions numbers listed above.

IThese toxics are: 1,3 Butadiene, Acetaldehyde, Acrolein, Benzene, Formaldehyde and PAHs.

Synapse Energy Economics - Title of Report Page 2 In addition to DR, the air impacts of 

### two diferent energy effciency programs were

explored: an energy-tageted program and a peak-tageted progrm. The energy-targeted 

### progrm reduced peak demand by one percent and annual energy use by 0.75 percent. 

### The peak-tageted progrm reduced pea demand by 1.2 percent and anual energy use

by 0.50 percent. These numbers were developed based 

### on a review of curent effciency progrm impacts in New England. 

## Results · In the economic DR progr modeled the DR resources provided 3,361 MWs of load relief durg the summer: 1,451 MWs of onsite generation and 1,910 MWhs of load response. Ths is over the times the amount of load relief provided by iso

New England's 2002 economic DR program (1,011 MW). This level of DR activity is consistent with our goal of modeling a matue DR progr in a moderately 

### capacity constrained year. DR resources would operate more in an extremely constrned period, such as the California crisis of 2000-200 1.

· Over 90 percent of 

### the DR load relief occur in southwestern Connecticut. Much of the 500-MW DR resource is never dispatched (includig all of the capacity in Maine,

New Hampshire and Rhode Island); however all of 

### the DR capacity is used to meet 

### operating reserve requirements durng the summer if allowed to do so. 

### · When the DR resource is used to meet reserve requirements, the result is more effcient unit commitment, reduced operation of oil- and gas-fired steam unts and increased operation of combined-cycle unts in New England. New England also 

### import more energy from neighboring control areas with the DR resource. The net

impact of these dynamics is a potential reduction in criteria pollutat emissions. However, in order to realize the NOx and S02 reductions, mechanisms would have to

be established to ensure that they were not lost though 

### emissions trading. 

### · Potential emission reductions in ths scenaro are largest in the summer months. Assuming no diesel generation in the DR progrm, sumer NOx reductions could be as large as 41 tons (0.18 percent); S02 reductions could be 218 tons (0.3 percent), and

C02 reductions could be 31,800 tons (0.13 percent). The impact of DR on mercur 

### emissions is negligible; however there ar small increases in several air toxics 

### associated with internl combustion (IC) engie generators. i · Ths fidig (potential emission reductions come from additional DR capacity used to meet reserve requirements) is specific to New England and should not be extrpolated 

### to other control areas. Furher, this findig is based on clearly identified assumptions about how the iso cuently commits generting unts and meets reserve requiments. To the extent that these assumptions do not captue the ful complexity 

### of this process, this fiding may need to be revaluated.
· Different assuptions about the mix of diesel- and gas-fired generation in the DR 

### progrm lead to small but significant impact on the emissions numbers listed above.

i These toxics are: 1,3 Butadiene, Acetadehyde, Acrolein, Benzene, Formldehyde and PAHs.

Synapse Energy Economics - Title of Report Page 2If we assume that 50 percent of the generation portion of the load relief is diesel fueled (rather than zero percent), the potential NOx benefits of the DR program are reduced by about 9 tons (22 percent). This level of diesel generation would reduce potential S02 benefits by about one ton (0.5 percent), and potential CO2benefits by about 200 tons (0.6 percent). It would reduce emissions of several air toxics associated with natural gas-fired ICs, but it would increase slightly emissions of PAHs and diesel fine particulates - the toxics that pose the greatest health threats. • When the DR resource is not used to meet reserve requirements, the impact on emissions is much smaller. Emissions of NOxcould either fall by about 4 tons or rise by about 15 tons, depending on the fuel mix of the DR generation. Emissions of C02 would fall, and emissions of the "IC toxics" would increase by small amounts. Because generators operating in DR programs are not subject to the NOx and S02 caps, and the units that they displace generally are subject to these caps, there is a potential source of "leakage" that should be of concern to air regulators. • While the net emissions impacts of DR operation (assuming it is not used to meet reserves) are small compared to total system emissions, in specific locations these impacts could exacerbate non-attainment problems and pose significant health risks. More work needs to be done to understand the health risks of operating IC generators in New England. • Comparing the impacts of the DR program to the single-year impacts of efficiency programs, we fmd that both efficiency prorams could provide significantly greater emission reductions than the DR program. The peak-targeted efficiency program could reduce annual emissions of NOx and S02 more than the energy-targeted program, but the energy-targeted program could reduce C02 the most. We use the term "could reduce," because efficiency programs (like DR programs) would have to ensure that NOx and S02 reductions were not lost through emissions trading in order to capture those reductions. • In the interest of estimating the emissions impacts of actual DR events retrospectively, we recommend that environmental regulators seek to obtain information on actual DR generation by plant type (e.g., diesel- versus gas-fired engine). Having this information would significantly reduce the uncertainty of these estimates, especially in a scenario in which DR is not used to meet reserve requirements.

2 We compare the effects of the efficiency programs to the effects of the DR program in which DR resources are used to meet reserve requirements.

Synapse Energy Economics - Title of Report Page 3 If we assume that 50 percent of the generation portion of the load relief is diesel

fueled (rather th zero percent), the potential NOx benefits of the DR program are reduced by about 9 tons (22 percent). This level of diesel generation would reduce potential S02 benefits by about one ton (0.5 percent), and potential CO2 benefits by about 200 tons (0.6 percent). It would reduce emissions of several air toxics associated with natual gas-fired ICs, but it would increase slightly emissions of 

### P AHs and diesel fine parculates - the toxics that pose the greatest health theats. 

### . When the DR resource is not used to meet reserve requirements, the impact on

emissions is much smaller. Emissions of NO x could either fall by about 4 tons or rise 

### by about 15 tons, depending on the fuel mix of the DR generation. Emissions of C02

would falL, and emissions of the "IC toxics" would increase by small amounts. Because generators operating in DR progrs are not subject to the NOx and S02 

### caps, and the unts that they displace generally are subject to these caps, there is a

potential source of 

### "leakge" that should be of concern to air regulators.

. While the net emissions impacts of 

### DR operation (assumg it is not used to meet reserves) are small compared to tota system emissions, in specific locations these impacts could exacerbate non-attinent problems and pose significant health risks. More work needs to be done to understad the health risks of operating IC generators 

### in New England. . Comparng the impacts of the DR program to the single-yea impacts of effciency progrms, we find that both effciency profam could provide significantly greater 

### emission reductions than the DR program. The peak-tageted effciency progrm

could reduce anual emissions of NO 

### x an S02 more than the energy-tageted program, but the energ-tageted program could reduce C02 the most. We use the 

### term "could reduce," because effciency progrms (like DR progrms) would have to ensure that NOx and S02 reductions were not lost though emissions trding in order to captue those reductions.
. In the interest of estimatig the emissions impacts of actual DR events retrospectively, we recommend that environmental reguators seek to obtain 

### inormtion on actul DR generation by plant tye (e.g., diesel- versus gas-fied 

### engine). Havig this inormtion would signficantly reduce the uncertinty of these estimates, especialy in a scenaro in which DR is not used to meet reserve 

### reqirements.

2 We compar the effects of the effciency progr to the effects of the DR progr in which DR
resours are used to meet resere requirements.

Synapse Energy Economics - Title of Report Page 3

## 1. Introduction

There has been increasing interest in recent years in demand response (DR), programs that incentivize electricity customers to reduce demand or operate on-site generators during periods of high loads and/or high prices. The benefits that DR could provide include lower market prices during certain hours, increased system reliability and mitigation of market power. However, along with these benefits, some types of DR programs could bring environmental costs in the form of increased air emissions from small, on-site generators that have been subject to little regulation in the past. In January 2003 Synapse began work to assess the potential emissions impacts of DR and energy efficiency programs in New England. Synapse performed this work under subcontract to Eastern Research Group, funded by the U.S. EPA. 3 EPA funded this project largely to inform the work ofthe New England Demand Response Initiative (NEDRI), a collaborative process designed to develop recommendations for expanding DR programs in New England. The key goals of the analysis were to: • Estimate the net emissions impacts of mature DR programs in New England under different assumptions, • Explore the impact of DR generating technology and fuel mix on net emissions, • Explore the extent to which additional DR capacity in New England could result in reduced air emissions from more efficient unit commitment, • Explore the impact ofload shifting on net emissions, and • Compare the emissions impact of DR programs to those of energy efficiency programs. The desire. to explore how DR could affect unit commitment grew out of a longer term discussion about the need for more quick-start capacity in New England. New England has a small amount of quick-start capacity relative to the regional peak load compared to most other control areas. Many analysts have noted that this requires large power plants to operate more than they would otherwise have to in order to maintain sufficient . operating reserves - capacity that can be provided quickly in response to unplanned losses of capacity. A key goal of this work for EPA was to verify that large units were indeed being operated more than necessary in New England to meet reserve requirements, to gauge the probable emissions impacts of this dynamic, and to estimate the potential emission reductions that additional DR could provide if it were used to meet operating reserve requirements. (This dynamic is discussed in more detail in Section 2.5). Finally, in addition to the work discussed above, EPA also requested that Synapse develop a methodology for estimating the emissions impacts of actual DR events retrospectively. This methodology is intended to complement the more predictive analysis discussed above by providing a way to estimate the impacts of actual DR activity after the fact. Together, the modeling work presented here and this methodology provide

3This work was performed under Contract 68-W-02-055, Task Order 007.

Synapse Energy Economics - Title of Report Page 4 

### 1. Introduction There has been increasing interest in recent years in demand response (DR), programs 

### that incentivize electrcity customers to reduce demand or operate on-site generators

durng periods of high loads and/or high prices. The benefits that DR could provide 

### include lower market prices durig certin hours, increased system reliability and

mitigation of market power. However, along with these benefits, some tyes of DR 

### programs could brig environmental costs in the form of increased ai emissions from small, on-site generators that have been subject to little regulation in the past.

In Janua 2003 Synapse began work to assess the potential emissions impacts of DR and 

### energy effciency programs in New England. Synapse performed this work under 

### subcontrct to Eastern Research Grup, fuded by the U.S. EPA. 3 EPA fuded this project largely to inform the work ofthe New Englad Demand Response Initiative 

### (NDRI, a collaborative process designed to develop recommendations for expanding
DR progrms in New England. The key goals of the analysis were to:

· Estimate the net emissions impacts of matue DR progrms in New England 

### under different assumptions,

· Explore the impact of 

### DR generatig technology and fuel mix on net emissions, 

### · Explore the extent to which additional DR capacity in New England could result in reduced air emissions from more effcient unit commtment, 

### · Explore the impact ofload shifting on net emissions, and 

### · Compare the emissions impact of DR progrs to those of energy effciency 

# progr. Thé desire. to explore how DR could affect unit commitment grew out of a longer term 

### discussion about the need for more quick-sta capacity in New England. New England 

### has a small amount of quick-sta capacity relative to the regional pea load compared to most other control areas. Many analysts have noted that this requires large power plants to operate more than they would otherwe have to in order to maintain suffcient ' operating reserves - càpacity that can be provided quickly in response to unplaned

losses of capacity. A key goal of 

### ths work for EPA was to verfy that large unts were indeed being operated more than necessar in New England to meet reserve

requirements, to gauge the probable emissions impacts of this dynamc, and to estiate the potential emission reductions that additional DR could provide if it were used to meet 

### operating reserve requirements. (This dynamc is discussed in more detail in Section 2.5). Finally, in addition to the work discussed above, EPA also requested that Synapse develop a methodology for estimating the emsions impacts of actual DR events 

### retrospectively. This methodology is intended to complement the more predictive analysis discussed above by providing a way to estimate the impacts of actul DR activity 

### aftr the fact. Together, the modeling work presented here and this methodology provide

3 Ths work wa performed under Contrct 68-W-02-055, Task Order 007.

Synapse Energy Economics - Title of Report Page 4a roadmap, identifying the dynamics that can be expected from increased DR activity in

New England, and a way toassess actual experience to determine if the intended results of new DR programs are indeed being realized. Section 2 of this report lays out the assumptions underlying the DR modeling work, and Section 3 presents the results of this work. Section 4 presents the methodology developed for assessing the emissions impacts of DR events retrospectively. 

## 2. Inputs and Assumptions The dispatch modeling portion of this analysis was performed with the PROSYMIMUL TISYM production costing model." Synapse licenses PROSYM from Henwood Energy Services, Inc., the company that developed the system and continuously updates it. The PROSYM system is used throughout the U.S. by well over 100 energy organizations, including generation companies, transmission companies and a wide variety of consultants. PROSYM is described in more detail in the Appendix. The input assumptions for this modeling work were developed with input from EPA and consultants to the NEDRI group with specific attention to the project goals. We modeled a hypothetical near-term year in New England, using projected 2006 fuel prices and loads. Region-specific prices for natural gas and oil (i.e., different prices for each control area) were developed from NYMEX futures prices as of January 2003. Plant-specific coal prices were developed from data reported by generating companies. For all fuels, PROSYM uses different prices for each month of the year. While fuel prices always represent an uncertainty in dispatch modeling, they do not represent an important uncertainty in this analysis, because the same fuel prices were used in both the reference case and the DR cases. It was agreed that a near-term year was preferable as the modeling year, as this would minimize the effects of assumptions about future plant additions and retirements. In any simulation of future system operation one must make an assumption about what kind of plants will be added to and retired from the system, and this assumption usually has a significant impact on the results of long-term studies. By choosing a near-term year as the study year, we were able to reduce the effect that this assumption had on the results. It was also agreed that we should model a relatively capacity-constrained year (i.e., a year in which there was likely to be robust DR operation) but not an extreme kind of capacity deficiency. We created a 20-percent system reserve margin by making minor adjustments to NEPOOL's projected plant in service in 2006. The plant in service for the study year is based on NEPOOL's 2002 Report on Capacity Energy Loads and Transmission (CELT). We adjusted this plant in service by "taking out" several proposed power plants, which the 2002 CELT assumed would be constructed by 2006.

4We use the term PROSYM to refer to the PROSYMIMUL TISYM system, because PROSYM is the more commonly known name of the system.

Synapse Energy Economics - Title of Report Page 5 a roadap, identifying the dynamics that can be expected from increased DR activity in
New England, and a way toassess actual experience to determine if the intended results 

### of new DR programs are indeed being realized.

Section 2 of this report lays out the assumptions underlying the DR modeling work, and 

### Section 3 presents the results of ths work. Section 4 presents the methodology

developed for assessing the emissions impacts of DR events retrospectively. 

# 2. Inputs and Assumptions The dispatch modeling portion of ths analysis was pedormed with the 

### PROSYM TISYM production costing modeL., Synapse licenses PROSYM from Henwood Energy Services, Inc., the company that developed the system and contiuously updates it. The PROSYM system is used thoughout the U.S. by well over i 00 energy organzations, including generation companes, trsmission companes and a wide varety of consultats. PROSYM is described in more detail in the Appendix. 

### The input assumptions for this modeling work were developed with input from EPA and consultats to the NEDRI group with specific attention to the project goals. We modeled 

### a hypothetical near-term year in New England, using projected 2006 fuel prices and 

### loads. Region-specific prices for natul gas and oil (i.e., different prices for each control 

### ar) were developed from NYX futues prices as of Januar 2003. Plant-specific coal prices were developed from data reported by generating companes. For all fuels,

PROSYM uss different prices for each month of the yea. While fuel prices always represent an uncertinty in dispatch modeling, they do not reresent an importt uncertinty in this anlysis, because the same fuel prices were used in both the reference 

### case and the DR cases. It was agee that a near-term year was preferable as the modeling year, as this would 

### mimize the effects of assumptions about futue plant addttions and retirements. In any 

### simulation of futue system operation one must mae an assumption about what kid of plants will be added to and retied from the system, and this assumption usually ha a signficant impact on the results of long-term studies. By choosing a nea-term yea as 

### the study year, we were able to reduce the effect that ths assumption had on the results. 

### It was also agree that we should model a relatively capacity-constrined year (i.e., a year in which there was likely to be robust DR operation) but not an extreme kid of capacity 

### deficiency. We created a 20-percent system reserve magin by mang mior adjusents to NEPOOL's projected plant in service in 2006. The plant in servce for the study yea is based on NEPOOL's 2002 Report on Capacity Energy Load and 

### Transmission (CELT). We adjusted this plant in service by "tang out' several proposed power plants, which the 2002 CELT assumed would be constrcted by 2006.

4 We use the tenn PROSYM to refer to the PROSYMUL TISYM syste, beaue PROSYM is the more

commnly known name of the system.

Synapse Energy Economics - Title of Report Page 5

### 2.1 The DR Program Modeled

We modeleda Day 

### Ahead Demand Response Program (DADRP). This is an economic DR program, one in which DR resources bid into the day-ahead energy market alongwith other supply-side resources and are dispatched based on their bids, just like supplyside resources. Importantly, the economic DR programs under development today aredifferent from the more common reliability-based DR programs. Under a reliabilitybased DR program, DR resources are dispatched based on a measure of system reliability or available reserves (such as OP 4, Step 12 status in New England). That is, DR resources are only dispatched when they are needed for system reliability. In contrast, DR resources are dispatched based entirely on their bids in an economic DR program, regardless of the load level or the status of reserves. We chose to investigate the environmental impacts of economic DR rather than emergency DR, because the impacts of economic DR are much more controversial and potentially much larger than those of emergency DR. There is more concern over the impacts of economic DR programs because these programs could potentially dispatch DR resources in far more hours of the year than emergency programs (which would dispatch DR only during emergencies). The DADRP program we modeled included 500 MW of DR capability. It was agreed that 500 MW is a reasonably good representation of a mature DR program in New England, based on currently available data. We modeled 60 percent of the DR capability as load response and 40 percent as generation. This ratio is based on data provided by ISO New England regarding recent (February 2003) enrollment in the New England economic DR program, (known then as the "Class 2" program). These data show a DR capability of roughly 75 MW, including 44 MW of load response (58 percent), 31 MW of generation (41 percent), and one MW of a combination of the two (one percent). The vast majority of the generators operated by electricity consumers in New England are either diesel- or natural gas-fueled internal combustion (lC) engines. While customersmay begin to use combustion turbines for peak shaving and other purposes over the longterm, we assume that IC engines will be the dominant generators used for DR for the foreseeable future. We explored DR scenarios involving several different mixes of .diesel- and gas-fired engines. Exploring different assumptions about the kind of engines providing DR genemtion was an important goal of both EPA and some NEDRIparticipants. Because economic DR programs will dispatch DR resources during nonemergency periods, generators whose air permits define them exclusively as emergency generators would presumably be precluded from participating in economic DR programs. However, there is currently very little information available on the status of onsite generators in New England, and many smaller ones have not been required to obtain an operating permit to date. Some customers with generators may not know if they could legally operate their unit for peak shaving rather than emergency purposes, because they have never had the opportunity to do so. Thus, it is important to explore scenarios in which confusion and other non-compliance problems lead to significant participation in economic DR programs by high-emitting emergency generators.

Synapse Energy Economics - Title of Report Page 6 \ 

# \ 2.1 The DR Program Modeled

wë modeieda Day Aheàd Demand 

### Response Program (DADRP). This is an economic 

### DR progra, one in which DR resources bid into the day-ahead energy market alongwith other supply-side resources and are dispatched based on their bids, just like supplyside resources. Importtly, the economic DR programs under development today are

### different from the more common reliabilty-based DR programs. Under a reliabiltybased DR program, DR resources are dispatched based on a measure of system reliability 

### or available reserves (such as OP 4, Step 12 sttus in New England). That is, DR resources are only dispatched when they are needed for system reliabilty. In contrst, 

### DR resources are dispatched based entirely on their bids in an economic DR program,

regardless of the load level or the status of reserves. We chose to investigate the environmental impacts of economic DR mther than emergency DR, because the impacts 

### of economic DR are much more controversial and potentially much larger than those of 

### emergency DR. There is more concern over the impacts of economic DR progrms

because these progrs could 

### potentially dispatch DR resources in far more hour of the year than emergency programs (which would dispatch DR only durng emergencies).

The DADRP program we modeled included 500 MW of 

### DR capabilty. It was agreed that 500 MW is a reasonably good representation of a matue DR progr in New

England, based on curently available data. We modeled 60 percent of the DR capability 

### as load response and 40 percent as generation. This mtio is based on data provided by iso New England regarding recent (Febru 2003) enrollment in the New England 

### economic DR progr, (kown then as the "Class 2" program). These data show a DR

capabilty of roughly 75 MW, including 44 MW of 

### load response (58 percent), 31 MW of genemtion (41 percent), and one MW of a combination of the two (one percent).

The vast majority of the generators operate by electrcity consumers in New England are 

### either diesel- or natul gas-fueled internal combustion (IC) engines. While customersmay begin to use combustion tubines for peak shaving and other purses over the long

### term we asume that IC engines wil be the dominant generators used for DR for the foresble futue. We explored DR scenarios involving seveml dierent mies of 

### , diesel- and gas-fied engines. Explorig differt assumptions about the kid of engies

providing DR genertion was an importt goal of 

### both EPA and some NEDRI

### parcipants. Because economic DR progrs wil dispatch DR resources durng nonemergency periods, generators ~ose air permits defie them exclusively as emergency 

### generators would presuably be precluded from partcipatig in economic DR progrs. However, there is curently very little informtion available on the statu of onsite generators in New England, and many smaller ones have not been required to obtain an

opemting permt to date. Some customers with generators may not know if 

### they could legally operate their unt for pea shaving rather than emergency purses, because they have never had the opportty to do so. Thus, it is importt to explore scenaros in 

### which confsion and other non-compliance problems lead to significant paricipation in 

### economic DR progrs by high-emittg emergency generators.

Synapse Energy Economics - Title of Report Page 6 \ 

## \On any given day, ISO New England must meet minute-to-minute demand for energy

and maintain sufficient reserves to deal with contingencies -unplanned outages of plants or transmission lines. Capacity maintained to deal with contingencies is called "operating reserves," and there are several different kinds. "Spinning reserves" are provided by generating units that are operating (synchronized to the grid) and can increase their output immediately upon being notified of a contingency. "Supplemental reserves" must be able to come online within 10 minutes of notification, and "replacement reserves" must be able to come online within 30 minutes. Importantly, supplemental and replacement reserves need not be provided by operating units; many combustion turbines and other units able to start quickly can provide these reserves. Further, these reserves could be provided by DR resources able to respond quickly and reliably." When considering the impact of DR on the way that reserve requirements are met in New England, it is important to note two changes that have taken place over the past year at ISO New England. First, ISO New England and the New York ISO have entered into a reserve sharing agreement, and second, ISO New England has implemented the Standard Market Design (SMD). The reserve sharing agreement with the New York ISO has reduced the amount of operating reserves that ISO New England must maintain in many hours of the year. The amount of reserve capacity available to New England via the agreement fluctuates based on load and transmission conditions in the respective control areas, but in many hours of the year it is in the range of200 to 300 MW. The implementation of SMD is important vis-a-vis reserves, because prior to SMD there were separate markets for energy and operating reserves in New England. Generating units could bid into either market, and if they were selected in one of the markets, they were paid the market-clearing price in that market. However, under the ISO's current implementation ofSMD, there are no longer separate markets for energy and reserves," The ISO clears the energy market and ensures adequate operating reserves in a two-step process. The first step of the process takes place in the Day-Ahead Market when the ISO takes the offers of all generating units (submitted on a day-ahead basis) and clears the energy 'market from primarily an economic perspective. illthis stage, the ISO's dispatch software designates units based on the participants' demand bids and each unit's energy offer. The software does consider the reserve requirement, but it does not 

### ensure that the reserve requirement is met. If the total load bid into the financial Day-Ahead Market is substantially less than the ISO forecast ofload, then the physical supply of reserve in real

6In New England, the amount of necessary operating reserves is calculated based on a scenario, in which the largest asset in the system and half of the second largest asset are assumed to fail simultaneously. During most hours of the year, the operating reserve requirement is in the range of 1,500 to 2,200 MW.

7A number of parties, including FERC, have recommended that reserve markets that are co-optimized with the energy market be established. ISO New England is in the process of developing and implementing such markets.

Synapse Energy Economics - Title of Report Page 9 On any given day, iso New England must meet minute-to-minute demand for energy and maita sufcient reserves to deal with contigencies -unplaned outages of plants or trmission lines. Capacity maintained to deal with contigencies is called 

### "operating reserves," and there are severl different kinds. "Spinng reserves" are provided by generating units that are operatig (synchronized to the grd) and can 

### increase their output immediately upon being notified of a contingency. "Supplemental reserves" must be able to come online within 10 minutes of notification, and "replacement reserves" must be able to come online within 30 minutes. Importtly, 

### supplemental and replacement reserves need not be provided by operating units; many 

### combustion tubines and other units able to sta quickly can provide these reserves. Furer, these reserves could be provided by DR resources able to respond quickly and reliably.6

When considerig the impact of DR on the way that reserve requirements are met in New

England, it is importt to note two changes that have taen 

### place over the past year at 

### iso New England. Firt, iSO New England and the New York iso have entered into a reserve sharng agreement, and second, iSO New England has implemented the Stadad 

### Market Design (SMD). The reserve sharig agreement with the New York iSO has reduced the amount of

operating reserves that iSO New England must maintain in many hour of the year. The

amount of 

### reserve capacity available to New England via the agreement fluctuates based 

### on load and tranmission conditions in the respective control areas, but in many hours of 

### the year it is in the rage of200 to 300 MW. The implementation of SMD is importt vis-à-vis reseres, because prior to SMD there were separte markets for energy and operatig reserves in New England. Generating

units could bid into either market, and if they were selected in one of the markets, they 

### were paid the market-elearing price in that market. However, under the iSO's curent

implementation ofSMD, there are no longer separte markets for energy and reserves.7 

### The iSO clears the energy market and ensur adequate operating reserves in a two-step process.

The fit step of 

### the process takes place in the Day-Ahead Maret when the iso taes the offers of al generating unit (submitted on a day-ahead basis) and clea the energy 'market from primaly an economic perspective. Ii this stage, the ISO's dispatch softare designtes units based on the paricipants' demand bids and each unit's energy offer. The softare does consider the resere requirement, but it does not ensure that the
reserve requiement is met. If the tota load bid into the financial Day-Ahead Market is substatially less th the iso forest ofload, then the physical supply of reserve in real

6 In New England, the amount of necssa operatig reerves is calculate based on a scenaro, in which

the largest asset in the system and hal of the secnd lagest asset ar assued to fail simultaeously.
Durg most hours of the year, the operting reserve requirment is in the rae of 1,500 to 2,200 MW. 7 A number of pares, including FERC, have reommended tht resere marets that ar co-tinuze with the energ maket be estalished. ISO New England is in the proces of developing and imlementig such makets.

Synapse Energy Economics - Title of Report Page 9time would fall short of requirements. This situation is prevented in the next step of the

process..the reserve adequacy analysis (RAA). In the RAA, the ISO determines whether the units committed in clearing the day-ahead energy market provide sufficient reserve capacity to meet the following day's reserve requirements. Ifthere is insufficient reserve capacity, additional units are selected in the RAA to meet the reserve requirements. Importantly, additional units are selected based on their startup and no-load costs, and the costs to operate those units at their respective economic minimum output. Therefore, a unit with a very high energy bid, but low startup and no-load costs, might well be selected to meet the reserve requirement. (In the real-time operation of the system, each unit's energy bid determines where it is dispatched. Thus, in the event of a contingency, reserve capacity is dispatched based on its energy bid.) By relying more on quick-start resources to meet reserve requirements, costs are. reduced and emissions are avoided, because these units can provide reserve capacity in a non-operating mode.8 When additional capacity must be added in the RAA, DR capacity would be likely to be selected, because it would likely have very low startup and noload costs. Thus, under the ISO's current implementation of SMD, if new DR resources were allowed to meet reserves, they would probably be used to do so often. However, once the region has sufficient quick-start capacity to meet reserve requirements efficiently, adding additional DR capacity would not provide additional emissions benefits in this way.


## 3. Results The modeling work performed here indicates that additional DR capacity can have significant emissions impacts in New England and that the most important variable affecting those impacts is whether or not the DR is used to meet reserve requirements or not. Other important variables include the fuel mix (diesel versus natural gas) of the engines providing the generation component of the DR and the extent to which loads reduced during DR events are shifted to other periods. The subsections below present the emissions impacts of the economic DR program modeled here under a number of different assumptions about program implementation and market responses.


## 3.1 DR and Power Plant Operation During the summer modeled, DR resources provided 3,361 MWhs ofloadrelief. Upon iterative analysis, we found total load relief(MWhs) to be stable within about ±1O

8Quick-start units that are designated to meet the reserve requirement but are not dispatched when providing reserves do not receive an energy payment. They do receive a-monthly leAP payment. In contrast, any units that are providing on-line reserves (i.e., operating) are eligible for "make-whole"· payments if their actual costs exceed their startup and no-load costs.

Synapse En.ergy Economics - Title of Report Page 10 

### time would fall short of requirements. This sitution is prevented in the next step of the

process,. the reserve adequacy analysis (R). In the RA, the iso determines whether the units commtted in clearng the day-ahead 

### energy market provide suffcient reserve capacity to meet the following day's reserve

requirements. Ifthere is insucient reserve capacity, additional units are selected in the 

### RA to meet the reserve requiements. Importntly, additional units are selected based on their stap and no-load costs, and the costs to operate those unts at their respective economic mium output. Therefore, a unt with a very high energy bid, but low 

### startp and no-load costs, might well be selected to meet the reserve requiement. (I the

real-time operation of 

### the system, each unt's energy bid determes where it is dispatched. Thus, in the event of a contingency, reserve capacity is dispatched based on its energy bid.) By relying more on quick-start resources to meet reserve requirements, costs are, reduced and emissions are avoided, because these units can provide reserve 

### capacity in a non-operatig mode.8 When additional capacity must be added in the RA, DR capacity would be likely to be selected, because it would likely have very low startp and noload costs. Thus, under the 

### ISO's curent implementation of SMD, if new DR resoures were allowed to meet reserves, they would probably be used to do so often. However, once the region has 

### suffcient quick-start capacity to meet reserve requirements effciently, adding additional DR capacity would not provide additional emissions benefits in this way.



## 3. Results The modeling work performed here indicates that additional DR capacity can have signcant emissions impact in New England and that the most importt varable 

### afecting those impacts is whether or not the DR is used to meet reserve requiements or 

### not. Other importt varables include the fuel mix (diesel versus natual gas) of the

engies providig the generation component of 

### the DR and the extent to which loads reduced durg DR events are shed to other penods. The subsections below present the emissions impacts of the economic DR progr modeled here l1der a number of different assumptions about program implementation and market responses. 

## 3.1 DR and Power Plant Operation
Durng the suer modeled, DR resources provided 3,361 MWs ofloadrelief. Upon 

### iterative analysis, we found total load relief(Ms) to be stable withi about:i1O

8 Quck-sta unts that are designted to meet the reserve requiment but ar not dispatched when providing reseres do not recive an ener payment. They do reive a,innthy ICAP payment. In
contrt. any unts that are providing on-line reseres (i.e., operting) ar eligible for "make-whole'" payments ¡ftheir actu costs exceed their st and no-load costs.

Synapse En.ergy Economics - Title of Report Page 102. Estimate emissions displaced by all DR activity, including both generation and load response, 3. Subtract displaced emissions from gross DR emissions to get the net emissions impact of DR generation and load response, 4. Estimate and add in emissions resulting from shifting 60percent of the loads curtailed to off-peak hours. Gross emissions from DR generation were calculated by multiplying projected generation by AP-42 emission factors. As above, we explored a range of assumptions about the fuel mix of DR generation. We estimate displaced emissions by analyzing (a) the ISO NE supply curve in the area where the DR resources bid, (b) model outputs in hours when. DR operated and (c) actual bid data published by ISO NE. This analysis reveals that oiland gas-fired combustion turbines (CTs) dominate this area of the supply curve, with blocks of oil- and gas-fired steam capacity interspersed. 12 Based on this analysis we estimate that roughly 70percent of the energy displaced by DR resources would have come from gas-fired CTs, 10percent from oil-fired CTs, 12 percent from gas-fired steam units, and three percent from oil-fired steam units. We calculate displaced emissions by multiplying the appropriate percentage of DR MWhs by the emission factors for each of these unit types. To estimate emissions from load shifting, we assume that 60percent of the energy use curtailed during DR events is shifted to the nighttime hours immediately following the event (We derive emission rates for shifted loads as described on page 15.) Table 8 shows the estimated net emissions from the dispatch of DR resources during the modeled summer, based on the methodology described above. Note that net emissions of NOx depend on the fuel mix of the DR generation; with the "all gas" scenario resulting in a net reduction and significant diesel-fired generation resulting in a net increase. Net C02 emissions fall across all fuel mix assumptions, primarily because the IC engines providing the DR energy are more efficient (and thus have lower CO2 emission rates) than the peaking turbines and steam units they displace. Emissions of S(h increase with the DR program. Emissions of both fme and coarse particulates increase small amounts with increased diesel generation, as do emissions of benzene and PAHs. Emissions of the air toxics associated with natural gas-fired ICs decrease with more diesel generation.

12 ISO bid data reveal that few large generating units bid all of their capacity at one price, and many large steam units bid their last blocks of capacity at very high prices.

Synapse Energy Economics - Title of Report Page 16 2. Estimate emissions displaced by all DR activity, including both generation and load response, 3. Subtrct displaced emissions from gross DR emissions to get the net emissions impact of DR generation and load response,

4. Estimate and add in emissions resulting from shifting 60 percent of the loads curiled to off-peak hours. Gross emissions from DR generation were calculated by multiplying projected generation 

### by AP-42 emission factors. As above, we explored a range of assumptions about the fuel

mix of 

### DR generation. We estimate displaced emissions by analyzing (a) the iso NE supply cure in the area where the DR resources bid, (b) model outputs in hours when

### , DR operated and (c) actual bid data published by iso NE. This analysis reveals that oiland gas-fired combustion tubines (CTs) dominte this area of 

### the supply cure, with blocks of oil- and gas-fired steam capacity interspersed.12 Based on this analysis we estimate that roughly 70 percent of the energy displaced by DR resources would have 

### come from gas-fired CTs, 10 percent frm oil-fired CTs, 12 percent from gas-fired steam 

### units, and thee percent from oil-fired steam units. We calculate displaced emissions by

multiplying the appropriate percentage of 

### DR MWs by the emission factors for each of these unit tyes.

To estimate emissions from load shifting, we assume that 60 percent of the energy use 

### curiled dunng DR events is shifted to the nighttime hours immediately followig the event (We derive emission rates for shifted loads as described on page 15.) Table 8 shows the estiated net emissions from the dispatch of DR resources dunng the modeled sumer, based on the methodology described above. Note that net emissions of

NOx depend on the fuel mix of the DR generation; with the "all gas" scenaro resulting in a net reduction and significant diesel-fired generation resulting in a net increase. Net 

### C02 emissions fall across all fuel mix assuiptions, primarly because the IC engines providing the DR energy are more effcient (and thus have lower CO2 emission rates) than the peaing turbines and steam unts they displace. Emissions of SOi increase with

the DR progr. Emissions of both fme and coarse parculates increase small amounts

with increased diesel generation, as do emissions of benene and PAHs. Emissions of the 

### air toXIcs associated with natul gas-fid ICs decrease with more diesel generation.

12 iso bid data revea that few lare generating unts bid all of their capacity at one price, and many large steam units bid their last blocks of capacity at very high prices.

Synapse Energy Economics - Title of Report Page 16

### 3.5 The Impacts of DR versus Energy Efficiency

In addition to estimating the net air impacts of DR programs, EPA and NEDRI were interested in comparing these impacts to those of common energy efficiency programs. To make this comparison, we modeled the following two energy efficiency programs: • An energy-targeted program providing a peak load reduction of one percent and an annual energy reduction of 0.75 percent • A peak-targeted program providing a peak load reduction of 1.2 percent and an annual energy reduction of 0.50 percent We examined the net air impacts of both of these program types in New England as well as a scenario in which the economic DR program was implemented along with the energy-targeted DR program. Before examining the results it is important to note several key differences between DR programs and efficiency programs. First, efficiency investments are by nature long-term investments, because the equipment installed continues to save energy for many years. In . contrast, an investment in DR might not reduce demand for multiple years. If the DR funds were spent on program design or the systems necessary to communicate with DR providers, they might provide multiple-year reductions. However, if the funds took the form of payments to DR providers, they would only provide one-time demand reductions. It is important to keep in mind this multiplier effect regarding the benefits of efficiency when comparing efficiency programs to DR programs. Second, it is difficult to compare an efficiency program and a DR program on a consistent basis. Efficiency equipment operates far more hours per year than DR is likely to be dispatched, and this includes more peak-oriented efficiency equipment, such as air conditioners. In order to make a "fair" comparison between efficiency and DR programs, we considered two normalizing approaches: peak load reduction and program costs. Neither of these proved to be an acceptable normalizing characteristic. An efficiency program that reduced peak loads by 500 MW (the amount of DR capacity modeled) would provide vastly greater emission reductions than the DR program. Thus, this did not seem like a fair comparison. In terms of program costs, we did not have enough information about the costs of implementing a DR program to normalize the two program types in this way. Thus, we have compared the DR program to a typical efficiency program, modeled on the kind of programs currently operating in New England. The peak load and energy reductions provided by the modeled efficiency programs (stated in the bullets above) are based on the kind of reductions being achieved by the efficiency programs underway in Connecticut, Massachusetts and Vermont Hence, while we model what we believe to be typical DR and efficiency programs, the comparison is something of an "apples to oranges" comparison, and it is important to keep the differences in the two program types in mind. Finally, note that energy efficiency programs face the same challenge that DR programs face regarding capped pollutants. If a generator receiving emission allowances operates less due to an efficiency program, the extra allowances can be sold to other generators, with the net effect being a reduction in the cost of meeting the cap rather than emission

Synapse Energy Economics - Title of Report Page 19 

## 3.5 The Impacts of DR versus Energy Effciency

In addition to estimating the net air impacts of 

### DR programs, EPA and NÊDRI were 

### interested in comparing these impacts to those of common energy efficiency progrms. To make this comparison, we modeled the following two energy effciency programs: 

### · An energy-tageted progrm providing a peak load reduction of one percent and

an anual energy reduction of 0.75 percent 

### · A peak-targeted progr providing a peak load reduction of 1.2 percent and an

annua energy reuction of 0.50 percent

We examined the net air impacts of both of 

### these progrm tys in New Englad as well as a scenao in which the economic DR progrm was implemented along with the energy-tageted DR program. 

### Before examing the results it is importt to note several key differences between DR progrms and effciency programs. First, effciency investments are by natue long-term investments, because the equipment instaled continues to save energy for may years. In .
contrast, an investment in DR might not reduce demand for multiple years. If 

### the DR 

### fuds were spent on program design or the systems necessar to communicate with DR

providers, they might provide multiple-year reductions. However, if the fuds took the

form of payments to DR providers, they would only provide one-time demand reductions. 

### It is importnt to keep in mind this multiplier effect regarding the benefits of effciency when comparng effciency progrs to DR progrs. 

### Second, it is difcult to compare an effciency progrm and a DR progrm on a consistent basis. Effciency equipment operates far more hours per year than DR is likely 

### to be dispatched and this includes more peak-oriented effciency equipment, such as air 

### conditioners. In order to make a "fait' comparson between effciency and DR programs, we considered two normlizing approaches: peak load reduction and program costs. 

### Neither of these proved to be an acceptable normalizing characteristic. An effciency

progrm that reduced pea loads by 500 MW (the amount of DR capacity modeled) would provide vastly greater emission reductions than the DR progr. Thus, this did not seem lie a fair comparson. In terms of progr costs, we did not have enough
information about the costs of implementing a DR progr to 

### normalize the two progrm tyes in this way. Thus, we have compared the DR progr to a tyical effciency program, modeled on the kind of program cuently operating in New England. The 

### pea load and energ reductions provided by the modeled effciency progrs (stated in the bullets above) are based on the kid of reductions being achieved by the effciency program underway in Connecticut, Massachusett and Vermont Hence, while we 

### model what we believe to be tyical DR and effciency progrms, the comparson is something of an "apples to oranges" comparson, and it is importt to keep the 

### differences in the two progr tyes in mind. Finly, note tht energy effciency programs face the same challenge that DR progrms face regarding capped pollutats. If a generator reciving emission allowances operates less due to an effciency progra, the extr allowances can be sold to other generators, 

### with the net effect being a reuction in the cost of meetig the cap rather than emission

Synapse Energy Economics - Title of Report Page 19

## 4. A Methodology for Assessing DR Events

Retrospectively In developing a method for assessing the net emissions impacts of actual DR events, one distinction is critical: whether or not DR resources are used to meet reserve requirements. If DR resources are used to meet reserve requirements, two dynamics must be assessed: (I) the emissions impacts of using DR for reserves and (2) the net emissions impacts of DR operation. If DR resources are not used to meet reserves, only the latter dynamic needs to be assessed. We outline methods for both scenarios. The method for assessing a summer in which DR resources are used to meet reserve requirements follows closely the method used in Task I of this project. First, emission reductions from the use of DR to meet reserves would be estimated by simulating plant commitment and dispatch in the region as closely as possible with an hourly dispatch model. Data on actual hourly loads, plant in service and plant outages could be obtained from ISO New England within six months to a year after the fact. It is possible that a confidentiality agreement would need to be signed with the ISO in order to obtain some of this information. The actual data on hourly loads plant in service and plant outages would be input into the model in order to simulate the historical year as accurately as possible. A Base Case year would be simulated, without the DR resources, and a "DR Case" would be run, which included all the DR resources that were enrolled in the program. If only a subset of the total DR resources were allowed to provide operating reserves, it would be important to make this distinction within the model. Second, emissions from DR operation would be estimated. If information on energy produced by different types of DR generator is available from the ISO, it should be used to .assess emissions. However, this information is unlikely to be available from the ISO or other sources during 2003 and perhaps 2004. In this case, emission factors would be applied to DR generation (MWhs) based on an assumption informed by any available data. These emission factors would be a significant source of uncertainty in the calculation, and we recommend that environmental regulators seek to obtain information on DR generation by plant type within a-reasonable time frame. Next the analysts would factor in emissions associated with shifted loads. Ideally, customers providing demand reductions would be interviewed to determine the amount of load shifting and the common times to which loads were shifted. Absent this kind of research, the analysts would have to make assumptions in these areas. In the work described above, we assume that 60 percent of the energy use curtailed during DR events is shifted to the nighttime hours immediately following the event. To derive emission rates for shifted loads, we recorded the range of nighttime load levels (hourly loads from 8:00 pm to 12:00 am) on each day in which DR resources were dispatched and then examined this load range in the ISO NE supply curve. The emission rates applied to shifted loads are a weighted average of the generating units in this load range. If DR resources were not used to meet reserves during the summer in question, then only the net effect of DR operation would need to be assessed. The method we propose for this scenario, laid out on pages 15 and 16 above, involves four steps. ",

Synapse Energy Economics - Title of Report Page 22 

## 4. A Methodology for Assessing DR Events 

# Retrospectively

In developing a method for assessing the net emissions impacts of 

### actual DR events, one 

### distinction is critical: whether or not DR resources are used to meet reserve requiements.

If 

### DR resources are used to meet reserve requiements, two dynamcs must be assessed:

(1) the emissions impacts of 

### using DR for reerves and (2) the net emissions impacts of

DR operation. If 

### DR resources are not used to meet reserves, only the latter dyaiic needs to be assessed. We outlne methods for both scenaros. 

### The method for assessing a sumer in which DR resources are used to meet reserve

requirements follows closely the method used in Task i of 

### this project. First, emission

reductions from the use of DR to meet reserves would be estiated by simulating plant 

### commitment and dispatch in the region as closely as possible with an hourly dispatch 

### modeL. Data on actul hourly loads, plant in servce and plant outages could be obtaned 

### from iso New England with six months to a year afer the fact. It is possible that a confidentiality agreement would need to be signed with the iso in order to obtan some 

### of this information. The actul data on hourly loads plant in servce and plant outages would be input into the model in order to simulate the historical year as accurtely as 

### possible. A Base Case year would be simulated, without the DR resources, and a "DR 

### Case" would be ru, which included all the DR resources that were enrolled in the program. If only a subset of the total DR resources were allowed to provide operating 

### reserves, it would be importt to make this distinction with the modeL. Secnd, emissions from DR operation would be estimated. If information on energy 

### produced by different tyes of DR generator is available from the iSO, it should be used 

### to ,assess emissions. However, ths inormation is unikely to be available from the iSO or other soures durng 2003 and perhaps 2004. In this case, emision factors would be applied to DR generation (Ms) based on an assumption informed by any available 

### data These emission factors would be a signficant source of uncertnty in the calculation, and we recommend that envinmenta regulators seek to obta inormation 

### on DR generation by plant tye within a-reasonable time frme. Next the analysts would factor in emissions associated with shifted loads. Ideally, customers providig demad reductions would be interviewed to detenne the amount 

### of load shiftng and the common times to which loads were shiftd. Absent this kind of research, the analysts would have to make assumptions in these areas. In the work

described above, we assume that 60 percent of 

### the energy use curiled durng DR events is shifted to the nightte hour immediately following the event. To derive emission 

### rates for shifed loads, we recorded the range of nightte load levels (hourly loads from 8:00 pm to 12:00 am) on each day in which DR resources were dispatched and then

examned this load rage in the iso NE supply cure. 

### The emission rates applied to
shifted loads are a weighted averae of the generating units in this load rage.

If DR resources were not used to meet reserves durg the sumer in question, then only

the net effect of 

### DR operation would need to be assessed. The method we propose for this scenaro, laid out on pages iS and 16 above, involves four steps. ',.

Synapse Energy Economics - Title of Report Page 221. Calculate gross emissions from DR generation. 2. Estimate emissions displaced by all DR activity, including both generation and load response. 3. Subtract displaced emissions from gross DR emissions to get the net emissions impact of DR generation and load response. 4. Estimate and add in emissions resulting from shifting 60 percent of the loads ..curtailed to off-peak hours. As discussed on pages 15 and 16, the analyst would develop an assumption about the resources displaced (step 2) based on a detailed analysis of the regional supply curve and actual bid data from the ISO. (The ISO currently releases bid data periodically.) This step is necessary because dispatch modeling would probably not provide reliable information on the net impacts of DR operation. IS After estimating displaced emissions, the consultant would factor in emissions from DR generation and from shifted loads as described on pages 15 and 16. Importantly, the consultant should also perform the sensitivity analyses necessary to describe the range of uncertainty around the results.

ISThe emission impacts of DR operation are likely to be small relative to total system emissions in most years, as the DR resource is likely to operate during a small portion of total summer hours. In an extreme case, where DR resources operated a large portion of the summer, these impacts could be assessed with a dispatch model. As discussed above, with the DR resource providing roughly 3,400 MWhs, we found that the emission impacts fell within the model's range of uncertainty (±O.05% change in total summer emissions).

Synapse Energy Economics - Title of Report Page 23 1. Calculate gross emissions from DR generation.

2. Estimate emissions displaced by all DR activity, including both generation and 

### load response. 

### 3. Subtract displaced emissions from gross DR emissions to get the net emissions impact of DR generation and load response.

4. Estimate and add in emissions resultig from shifting 60 percent of the loads 

### . curiled to off-peak hours. As discussed on pages 15 and 16, the analyst would develop an assumption about the

resources displaced (step 2) based on a detailed analysis of the regional supply cure and 

### actul bid data from the iso. (Te iSO curently releases bid data periodically.) This step is necessar because dispatch modeling would probably not provide reliable

information on the net impacts of DR operation. IS Aftr estimating displaced emissions, 

### the consultat would factor in emissions from DR generation and from shifted loads as described on pages 15 and 16. Importtly, the consultat should also perform the 

### sensitivity analyses necessar to describe the range of uncertinty around the results.

IS The emission impacts of DR operaton are likely to be smll relative to tota system emissions in most yea, as the DR resoure is likely to operate durng a small portion of tota suer hour. In an extreme cae, where DR resours opeted a large portion of the sumer, these impacts could be assessed with a dispatch modeL. As discussed above, with the DR resource providig roughly 3,400 MWhs, we found
tht the emssion impact fell withi the modl's rage of uncertinty (:l.05% change in total sumer emissions).

Synapse Energy Economics - Title of Report Page 23

## Appendix: The PROSYM/MULTISYM Model

Synapse licenses PROSYM from Henwood Energy Services, Inc., the company that developed the system and continuously updates input data for it. 16 The modeling system is used throughout the United Stats by well over 100 energy organizations, including generation companies, transmission companies, and a wide variety of consultants. Thus, work performed with PROSYM is readily transferable to other regions, and additional analyses can be performed in the future by a wide variety of industry analysts. The basic geographic unit in PROSYM is a subregion of a control area, called a "transmission area." Transmission areas are defined in practice by actual transmission constraints within a control area. That is, power flows from one area to another in a control area are governed by the operational characteristics of the actual transmission lines involved. ISO New England, for example, consists often transmissionareas. Hourly load data are entered into PROSYM by distribution utility area, meaning that policy implementation can be simulated at the utility level. PROSYM can also simulate operation in any number of control areas. Synapse models groups of contiguous control areas in order to capture all regional impacts of the dynamics under scrutiny. When assessing New England, Synapse usually simulates operation in New England, New York, PJM, and the three control areas in Southeast Canada. Model outputs can be sorted in a variety of ways. Results can be assessed by control area to discern the larger geographic distribution of impacts or by state or transmission area for higher resolution analysis. Similarly, changes in unit operation by fuel type can be explored to assess impacts on different classes of generator. PROSYM operates using hourly load data and simulates unit dispatch in chronological order. In other words, 8,760 distinct load levels are entered for each transmission area for each study year. The model begins on January 1st and dispatches generating units to meet load in each hour of the year. Using this chronological approach, PROSYM takes into account time-sensitive dynamics such as transmission constraints and the operating characteristics of specific generating units. For example, one power plant might not be . available at a given time due to its minimum down time (i.e., the period it must remain off line once it is taken oft). Another unit might not be available to a given transmission area because of transmission constraints created by current operating conditions. These are dynamics that system operators wrestle with daily, and they often cause generating units to be dispatched out of merit order. Few other electric system models simulate dispatch in this kind of detail. Many models use as load data step functions or load duration curves for representative time periods. Rather than simulating unit dispatch on each day of a future summer, for example, these models dispatch units to meet several types of summer days and then extrapolate predicted unit operation for those hours to the entire summer. This type of model does not allow the user to explore the operation of DR programs, which are implemented for several hours on a handful of days each year.

16This model is technically called MULTISYM when more than one control area is being modeled, as in this project. However, we use the term PROSYMthroughout this description because it is the model's more commonly known name.

Synapse Energy Economics - Title of Report Page 24 

## Appendix: The PROSYM/MULTISYM Model Synapse licenses PROSYM from Henwood Energy Servces, Inc., the company that developed the system and continuously updates input data for it. 16 The modeling system 

### is used thoughout the United Stats by well over i 00 energy organzations, including generation companes, tranmission companies, and a wide varety of consultats. Thus, 

### work performed with PROSYM is readily trferable to other regions, and additional analyses can be pedormed in the futue by a wide varety of industr analysts. The basic geographic unt in PROSYM is a subregion of a control area, called a 

### "trsmission area." Transmission areas are defied in practice by actual transmission constraints within a control area. That is, power flows from one area to another in a

control area are governed by the operational charactenstics of 

### the actual trsmission lines involved. iso New England, for example, consists often trsmissionareas. 

### Hourly load data are entered into PROSYM by distrbution utility area, meang that policy implementation can be simulated at the utilty leveL. 

### PROSYM can also simulate operation in any number of control areas. Synapse models

groups òf contiguous control area in order to captue all regional impacts of 

### the dynamics under scrutiny. When assessing New England, Synapse usually simulates 

### operation in New England, New Yorl" PJM, and the thee control areas in Southeast 

### Canada. Model outputs can be sorted in a varety of ways. Results can be assessed by 

### control area to discer the larger geogrphic distrbution of impacts or by state or trnsmission area for higher resolution analysis. Similarly, changes in unt operation by 

### fuel tye can be explored to assess impacts on different classes of generator. 

### PROSYM operates using hourly load data and sinulates unt dispatch in chronological 

### order. In other words, 8,760 distinct load levels are entered for each trmission ara for each study yea. The model begin on Janua I st and dispatches generating unts to

meet load in each hour of the yea. Using this chronological approach, PROSYM taes into account tie-sensitive dynamcs such as trsmission constrts and the operatig
chaactestics of specific generating unts. For example, one power plant might not be , available at a given time due to its minimum dQwn time (i.e., the penod it must rema off line once it is taen oft. Another unit might not be available to a given trsmission

area because of trsmission constrnts created by curent operating conditions. These 

### are dynamics that system operators wrestle with daily, and they often cause generating 

### unts to be dispatched out ofment order. Few other electrc system models simulate 

### dispatch in this kid of detail. Many models use as load data step fuctons or load durtion cures for representative time penod. Rather than sinulating unit dispatch on each day of a futue summer, for example, these models dispatch unts to meet severa 

### tyes of summer days and then extrpolate prected unt operation for those hour to the entire sumer. Ths tye of model does not allow the user to explore the operation of 

### DR programs, which are implemented for several hour on a handful of days each year.

16 Ths moel is techncally called MULTISYM when more than one control area is being modeled as in this project. However, we use the tenn PROSYMthughout ths description because it is the model's more commonly known name.

Synapse Energy Economics - Title of Report Page 24PROSYM also uses highly detailed information on generating units. For larger units,

emission rates and operating characteristics are based on unit-specific data reported to EPA and EIA rather than on data based on unit type. Operating costs for each unit are based on plant-level operating costs reported to FERC and assessment of unit type and age. In some cases, plant owners have been contacted to verify input data. For smaller units (e.g., combustion turbines), most input data are based on unit type. All generating units in PROSYM operate at different heat rates (efficiencies) at different loading levels. In contrast, many models simply apply one heat rate to each unit at all load levels. This distinction is especially important in the case of combined-cycle units, which often operate in a simple-cycle mode at low loadings. PROSYM determines the fuel a unit burns by placing a generating unit into a "fuel group." PROSYM does not limit the number of fuel groups used, and creating new fuel groups to simulate a few unusual units is a simple matter. Over the course of past projects focused on the Northeast, Synapse has often adjusted unit fuel groupings to better simulate the operation of dual-fueled units. PROSYM calculates emissions of NO x, S02, and CO2based on unit-specific emission rates. Emissions of other pollutants (e.g., particulates and air toxics) are calculated from emissions factors applied to fuel groups. Synapse also commonly includes in base-case assumptions the effects of all existing air regulations. Allowance costs associated with the Ozone Transport Commission (OTC) NOx Budget Program and the Acid Rain Program are included in unit operating costs, and results are checked to ensure that the NOx cap is not exceeded. PROSYM simulates the effects of forced (i.e., random) outages probabilistically, using one of several Monte Carlo simulation modes. These simulation modes initiate forced outage events (full or partial) based on unit-specific outage probabilities and a Monte Carlo-type number draw. Many other models simulate the effect of forced outages by derating the capacity of all generators within the system. That is, the capacities of all units are reduced at all times to simulate the outage of several units at any given time. While derating usually results in a reasonable estimate of the amount of annual generation from baseload plants, the result for intermediate and peaking units can be inaccurate, and very inaccurate over short periods. This issue is very important when modeling DR programs, which operate mostly, or even exclusively, during system peak hours.

Synapse Energy Economics - Title of Report Page 25 

### PROSYM also uses highly detailed information on generating units. For larger units, 

### emission rates and operating characteristics are based on unt-specific data reported to EPA and EIA rather than on data based on unit tye. Operating costs for each unt are 

### based on plant-level operating costs reported to FERC and assessment of unit tye and age. In some cases, plant owners have been contacted to verify input data. For smaller 

### units (e.g., combustion tubines), most input data are based on unit tye. All generating units in PROSYM operate at different heat rates (effciencies) at different loading levels. 

### In contrast, many models simply apply one heat rate to each unt at all ioad levels. This 

### distinction is especially importt in the case of combined-cycle units, which often operate in a simple-cycle mode at low loadings. PROSYM determines the fuel a unit burs by placing a generating unit into a "fuel group." PROSYM does not limit the number of fuel groups used, and creating new fuel groups to simulate a few unusual unts

is a simple matter. Over the coure of past projects focused on the Norteast, Synapse 

### has often adjusted unit fuel groupings to better simulate the operation of dual-fueled 

### unts.

PROSYM calculates emissions of NO x, S02, and CO2 based on unt-specific emission rates. Emissions of other pollutats (e.g., parculates and air toxics) are calculated from 

### emissions factors applied to fuel groups. Synapse also commonly includes in base-case 

### assumptions the effects of all existing air regulations. Allowance costs associated with 

### the Ozone Trasport Commssion (OTC) NOx Budget Program and the Acid Rai Progrm are included in unit operating costs, and results are checked to ensure that the NOx cap is not exceeded.

PROSYM simulates the effects of 

### forced (i.e., random) outages probabilstically, using 

### one of several Monte Carlo simulation modes. These simulation modes intiate forced 

### outage events (full or parial) based on unt-specific outage probabilties and a Monte

Calo-ty number drw. Many other models simulate the effect of forced outages by 

### deratig the capacity of all generators within the system. That is, the capacities of all units ar redced at all times to simulate the outage of several unts at any given time. 

### Whle derating usually results in a reasonable estimate of the amount of anual generation from baseload plants, the result for intermedate and peakg unts can be 

### inaccurte, and very inaccurate over short period. This issue is very importnt when 

### modelig DR progr, which operate mostly, or even exclusively, durng system peak 

### hour.

Synapse Energy Economics - Title of Report Page 25

# Attachment 2

North American Electric Reliability Council Standard EOP-002-2.1 - Capacity and Energy Emergencies 

# Attachment 2



# North American Electric Reliability Council 

# Standard EOP-002-2.1 - Capacity and Energy EmergenciesStandard EOP-002·2.1 - Capacity and Energy Emergencies

A. Introduction 1. Title: Capacity and Energy Emergencies 2. Number: EOP-002-2.1 3. Purpose: To ensure Reliability Coordinators and Balancing Authorities are prepared for capacity and energy emergencies. 4. Applicability 4.1. Balancing Authorities. 4.2. Reliability Coordinators. 4.3. Load-Serving Entities. 5. Effective Date: May 13, 2009 B. Requirements Rl. Each Balancing Authority and Reliability Coordinator shall have the responsibility and clear decision-making authority to take whatever actions are needed to ensure the reliability of its respective area and shall exercise specific authority to alleviate capacity and energy emergencies. R2. Each Balancing Authority shall implement its capacity and energy emergency plan, when required and as appropriate, to reduce risks to the interconnected system. R3. A Balancing Authority that is experiencing an operating capacity or energy emergency shall communicate its current and future system conditions to its Reliability Coordinator and neighboring Balancing Authorities. R4. A Balancing Authority anticipating an operating capacity or energy emergency shall perform all actions necessary including bringing on all available generation, postponing equipment maintenance, scheduling interchange purchases in advance, and being prepared to reduce firm load. R5. A deficient Balancing Authority shall only use the assistance provided by the Interconnection's frequency bias for the time needed to implement corrective actions. The Balancing Authority shall not unilaterally adjust generation in an attempt to return Interconnection frequency to normal beyond that supplied through frequency bias action and Interchange Schedule changes. Such unilateral adjustment may overload transmission facilities. R6. If the Balancing Authority cannot comply with the Control Performance and Disturbance Control Standards, then it shall immediately implement remedies to do so. These remedies include, but are not limited to: R6.1. Loading all available generating capacity. R6.2. Deploying all available operating reserve. R6.3. Interrupting interruptible load and exports. R6.4. Requesting emergency assistance from other Balancing Authorities. R6.5. Declaring an Energy Emergency through its Reliability Coordinator; and
Adopted by 80ard of Trustees: October 29, 2008 Effective Date: May 13, 2009 Page 1 of13 Standard EOP-002.2.1 - Capacity and Energy Emergencies

A. Introduction l. Title: Capacity and Energy Emergencies 2. Number: EOP-002-2.l 3. Purpose: To ensure Reliability Coordinators and Balancing Authorities are prepared 

### for capacity and energy emergencies. 4. Applicabilty 4.1. Balancing Authorities. 4.2. Reliabilty Coordinators. 4.3. Load-Serving Entities. 5. Effective Date: May 13, 2009 

### B. Requirements Rl. Eah Balancing Authority and Reliabilty Coordinator shall have the responsibilty and 

### clear decision-making authority to tae whatever actions are needed to ensure the 

### reliabilty of its respective area and shall exercise specific authority to aleviate capacity and energy emergencies. 

### R2. Each Balancing Authority shall implement its capacity and energy emergency plan, when required and as appropriate, to reduce risks to the interconnected system. 

### RJ. A Balancing Authority that is experiencing an ,operating capacity or energy emergency 

### shall communicate its curent and futue system conditions to its Reliabilty Coordinator and neighboring Balancing Authorities. 

### R4. A Balancing Authority anticipatig an operatig capacity or energy emergency shall perform all actions necessa includig brigig on all available genertion, 

### postpning equipment maintenance, scheduling interchange purchases in advance, and being prepared to reduce fi load. 

### RS. A deficient Balancing Authority shall only use the assistace provided by the Interconnection's frequency bias for the time needd to implement corrective actions. The Balancing Authority shall not unlateraly adjust generation in an attempt to retu Interconnection frequency to normal beyond that supplied though frequency bias 

### action and Interchange Schedule changes. Such unilatera adjustment may overload 

### trsmission facilties. 

### R6. If the Balancing Authority caot comply with the Control Performce and Distubance Control Stadads, then it shall imediately implement remedes to do so. These remedies include, but are not limite to: R6.1. Loading all available generatig capacity. 

### R6.2. Deploying all available operating reserve. 

### R6.3. Interrpting interrptible load and export. R6.4. Requestig emergency assistace from other Balancing Authorities. R6.5. Declarg an Energy Emergency though its Reliabilty Coordator; and Adopted by eoard of Trustees: October 29, 2008 Effecve Date: May 13, 2009 Page 1 of13Standard EOP-002-2.1 - Capacity and Energy Emergencies

R6.6. Reducing load, through procedures such as public appeals, voltage reductions, curtailing interruptible loads and firm loads. R7. Once the Balancing Authority has exhausted the steps listed in Requirement 6, or if these steps cannot be completed in sufficient time to resolve the emergency condition, the Balancing Authority shall: R7.1. Manually shed firm load without delay to return its ACE to zero; and R7.2. Request the Reliability Coordinator to declare an Energy Emergency Alert in accordance with Attachment l-EOP-002-0 "Energy Emergency Alert Levels." R8. A Reliability Coordinator that has any Balancing Authority within its Reliability Coordinator area experiencing a potential or actual Energy Emergency shall initiate an Energy Emergency Alert as detailed in Attachment l-EOP-002-0 "Energy Emergency Alert Levels." The Reliability Coordinator shall act to mitigate the emergency condition, including a request for emergency assistance if required. R9. When a Transmission Service Provider expects to elevate the transmission service priority of an Interchange Transaction from Priority 6 (Network Integration Transmission Service from Non-designated Resources) to Priority 7 (Network: Integration Transmission Service from designated Network Resources) as permitted in its transmission tariff (See Attachment l-IRO-006-0 "Transmission Loading Relief Procedure" for explanation of Transmission Service Priorities): R9.I. The deficient Load-Serving Entity shall request its Reliability Coordinator toinitiate an Energy Emergency Alert in accordance with Attachment 1-EOP002-0. R9.2. The Reliability Coordinator shall submit the report to NERC for posting on the NERC Website, noting the expected total MW that may have its transmission service priority changed. R9.3. The Reliability Coordinator shall use EEA 1 to forecast the change of the priority of transmission service of an Interchange Transaction on the system from Priority 6 to Priority 7. R9.4. The Reliability Coordinator shall use EEA 2 to annouIice the change of the priority of transmission service of an Interchange Transaction on the system from Priority 6 to Priority 7. C. 

### Measures MI. Each Reliability Coordinator and Balancing Authority shall have and provide upon request evidence that could include but is not limited to, job descriptions, signed agreements, authority letter signed by an appropriate officer of the company, or other equivalent evidence that will be used to confirm that it meets Requirement 1. M2. If a Reliability Coordinator or Balancing Authority implements its Capacity and Energy Emergency plan, that entity shall have and provide upon request evidence that could include but is not limited to, operator logs, voice recordings or transcripts of voice recordings, electronic communications, computer printouts or other equivalent evidence that will be used to determine if the actions it took to relieve emergency

Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13,2009 Page 2 of 13 Standard EOP-02-2.1 - Capacity and Energy Emergencies


### R6.6. Reducing load, through procedures such as public appeals, voltage reductions,

curilng interrptible loads and firm loads. 

### R7. Once the Balancing Authority has exhausted the steps listed in Requirement 6, or if these steps canot be completed in suffcient time to resolve the emergency condition, 

### the Balancing Authority shall: 

### R7.i. Manually shed fi load without delay to retu its ACE to zero; and

R7.2. Request the Reliabilty Coordinator to declare an Energy Emergency Alert in 

### accordance with Attchment l-EOP-002-0 "Energy Emergency Alert Levels." 

### R8. A Reliabiltý Coordinator that has any Balancing Authority with its Reliability Coordinator area experiencing a potential or actul Energy Emergency shall intiate an Energy Emergency Alert as detailed in Attchment l-EOP-002-0 "Energy Emergency 

### Alert Levels." The Reliability Coorditor shall act to mitigate the emergency

condition, includig a request for emergency assistace if required. 

### R9. When a Tramission Service Provider expects to elevate the trsmission service priority of an Interchange Trasaction from Priority 6 (Network Integration 

### Transmission Servce from Non-designated Resoures) to Priority 7 (Network

Integrtion Trasmission Service from designated Network Resoures) as permitted in its trsmission taff (See Attchment l-IRO-006-0 "Tranmission Loadig Relief
Procedure" for explanation of Trasmission Service Priorities): 

### R9.I. The deficient Load-Serving Entity shall request its Reliabilty Coordinator to

### intiate an Energy Emergency Alert in accordace with Attchment l-EOP002-0. 

### R9.2. The Reliabilty Coordinator shall submit the report to NERC for posting on the NERC Website, notig the expected total MW that may have its transmission service priority changed.

R9.3. The Reliabilty Coordiator shal use EEA 1 to forecast the change of the

priority of trmission servce of an Interchange Ti:ansaction on the system from Priority 6 to Priority 7. R9.4. The Reliabilty Coorditor shall use EEA 2 to anouice the change of the

priority of trsmission service or 

### an Interchange Traaction on the system from Priority 6 to Priority 7. 

### C. Measures MI. Each Reliability Coordinator and Balancing Authority shall have and provide upon request evidence that could include but is not limited to, job descriptions, signed

agreements, authority letter signed by an appropriate offcer of 

### the company, or other 

### equivalent evidence that wil be used to conf that it meets Requirement 1. M2. If a Reliabilty Coordinator or Balancing Authority implements its Capacity and Energy Emergency plan, that entity shall have and provide upon request evidence that 

### could include but is not limited to, operator logs, voice recordings or trancripts of 

### voice recrdings, electrnic communcations, computer printouts or other equivalent evidence that wil be used to determe if the actions it took to ~elieve emergency

Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13,2009 Page 2 of 13Standard EOP-002·2.1 - Capacity and Energy Emergencies
conditions were in conformance with its Capacity and Energy Emergency Plan. (Requirement 2) M3. If a Balancing Authority experiences an operating Capacity or Energy Emergency it shall have and provide upon request evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine if it met Requirement 3. M4. If a Reliability Coordinator has any Balancing Authority within its Reliability Coordinator Area that has notified the Reliability Coordinator of a potential or actual Energy Emergency, the Reliability Coordinator involved in the event shall have and provide upon request evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence to determine ifit initiated an Energy Emergency Alert as specified in Requirement 8 and as detailed in Attachment I·EOP·002 Energy Emergency Alert Levels. MS. If a Transmission Service Provider expects to elevate the transmission service priority of an Interchange Transaction from Priority 6 (Network Integration Transmission Service from Non-designated Resources) to Priority 7 (Network Integration Transmission Service from designated Network Resources), the Reliability Coordinator involved in the event shall have and provide upon request" evidence that could include, but is not limited to, NERC reports, EEA reports, operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine ifthat Reliability Coordinator met Requirements 9.2, 9.3 and 9.4. D. Compliance 1. Compliance Monitoring Process 1.1. Compliance Monitoring Responsibility Regional Reliability Organizations shall be responsible for compliance monitoring. 1.2. Compliance Monitoring and Reset Timeframe One or more of the following methods will be used to assess compliance: - Self-certification (Conducted annually with submission according to schedule.) . - Spot Check Audits (Conducted anytime with up to 30 days notice given to prepare.) - Periodic Audit (Conducted once every three years according to schedule.) - Triggered Investigations (Notification of an investigation must be made within 60 days of an event or complaint of noncompliance. The entity will have up to 30 days to prepare for the investigation. An entity may request an extension of the preparation period and the extension will be considered by the Compliance Monitor on a case-by-case basis.)

Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13, 2009 Page 3 of13 Standard EOP-002-2.1 - Capacit and Energy Emergencies
conditions were in conformance with its Capacity and Energy Emergency Plan. (Requirement 2) 

### M3. If a Balancing Authority experiences an operatig Capacity or Energy Emergency it shall have and provide upon request evidence that could include, but is not limited to operator logs, voice recordings or trscripts of voice recordings, electronic 

### communications, or other equivalent evidence that wil be used to determne if it met Requirement 3. 

### M4. If a Reliability Coordinator has any Balancing Authority within its Reliabilty Coordinator Area that has notified the Reliabilty Coordinator of a potential or actul Energy Emergency, the Reliabilty Coordinator involved in the event shall have and provide upon request evidence that could include, but is not lited to operator logs,
voice recordings or transcripts of voice recordings, eleconic communcations, or other 

### equivalent evidence to determine if it intiated an Energy Emergency Alert as specified 

### in Requirement 8 and as detailed in Attchment I-EOP-002 Energy Emergency Alert Levels. 

### MS. If a Transmission Service Provider expects to elevate the trsmission service priority 

### of an Interchange Trasaction from Prority 6 (Network Integrtion Trasmission Service from Non-designated Resources) to Priority 7 (Network Integrtion Transmission Service from designated Network Resources), the Reliabilty Coordinator involved in the event shall have and provide upon request evidence that could include, 

### but is not limited to, NERC report, EEA reports, operator logs, voice recordings or

trnscripts of voice recordings, electronic communcations, or other equivalent 

### evidence that wil be used to determine ifthat Reliabilty Coordinator met Requirements 9.2, 9.3 and 9.4. 

### D. Compliance 1. Compliance Monitoring Process 

### 1.1. Compliance Monitoring Responsibilty Regional Reliability Organzations shall be responsible for compliance monitoring. 

### 1.2. Compliance Monitorig and Reset Timeframe One or more of the followig methods wil be used to assess compliance:
- Self-certification (Conducted anually with submission according to 

### schedule.) . 

### - Spot Check Audits (Conducted anytme with up to 30 days notice given to prepare.)
- Periodic Audit (Conducted once every thee year according to schedule.) - Triggered Investigations (Notication of an investigation must be made 

### within 60 days of an event or complaint of noncompliance. The entity will 

### have up to 30 days to prepare for the investigation. An entity may request an

extension of the prepartion period and the extension will be considered by the Compliance Monitor on a case-by-cae basis.)
Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13, 2009 Page 3 of13Standard EOP..()02·2.1 - Capacity and Energy Emergencies

The Performance-Reset Period shall be 12 months from the last finding of noncompliance. 1.3. Data Retention For Measure 1, each Reliability Coordinator and Balancing Authority shall keep The current in-force documents. For Measure 2, 4 and 5 the Reliability Coordinator shall keep 90 days of historical data. For Measure 3 the Balancing Authority shall keep 90 days of historical data. If an entity is found non-compliant the entity shall keep information related to the noncompliance until found compliant or for two years plus the current year, whichever is longer. Evidence used as part of a triggered investigation shall be retained by the entity being investigated for one year from the date that the investigation is closed, as determined by the Compliance Monitor. The Compliance Monitor shall keep the last periodic audit report and all requested .and submitted subsequent compliance records. 1.4. Additional Compliance Information None. 2. Levels of Non-Compliance for a Reliability Coordinator: 2.1. Levell: Did not submit the report to NERC as required in R9.2. 2.2. Level 2: Not applicable. 2.3. Level 3: Not applicable. 2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the following requirements that is in violation: 2.4.1 One or more of the actions of the Capacity and Energy Emergency Plans were not implemented as appropriate. (R2) 2.4.2 There is no evidence an Emergency Alert was issued as specified in R8 2.4.3 Failed to comply with R9.3 or R9.42.4.4 Did not provide evidence that it has the responsibility and clear decisionmaking authority in accordance with Rl. 3. Levels of Non-Compliance for a Balancing Authority: 3.1. Levell: Not applicable. 3.2. Level 2: Did not provide evidence that it has the responsibility and clear decision-making authority in accordance with RI. 3.3. Level 3: Not applicable.

Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13, 2009 Page40f13 Standard EOP.Q02.2.1 - Capacity and Energy Emergencies



### The Performance-Reset Penod shall be 12 months from the last finding of noncompliance. 1.3. Data Retention

For Measure 1, each Reliabilty Coordinator and 

### Balancing Authonty shall keep The curent in-force documents. 

### For Measure 2, 4 and 5 the Reliability Coordinator shall keep 90 days ofhistoncal data. For Measur 3 the Balancing Authonty shall keep 90 days ofhistoncal data. 

### If an entity is found non-compliait the entity shall keep information related to the 

### noncompliance until found compliant or for two years plus the curent year, whichever is longer. Evidence used as part of a trggered investigation shall be retained by the entity 

### being investigated for one year from the date that the investigation is closed, as determned by the Compliance Monitor. 

### The Compliance Monitor shall keep the last penodic audit report and all requested ,and sùbmitted subsequent compliance records. 

### 1.4. Additional Compliance Information None.

2. Levels of 

### Non-Compliance for a Reliabilty Coordinator:

2.1. Levell: Did not submit the report to NERC as requird in R9.2. 2.2. Level 2: Not applicable. 2.3. Level 3: Not applicable.

2.4. Level 4: There shall be a separte Level 

### 4 non-compliance, for every one of the 

### followig requirements that is in violation: 2.4.1 One or more of the actions of the Capacity and Energy Emergency Plan 

### were not implemented as appropnate. (R2) 2.4.2 There is no evidence an Emergency Alert was issued as specified in R8
2.4.3 Failed to comply with R9.3 or R9.4

### 2.4.4 Did not provide evidence that it has the responsibilty and clear decision

### mag authonty in accrdace with RL.

3. Levels of 

### Non-Compliance for a Balancing Authority:
3.1. Levell: Not applicable. 

### 3.2. Level 2: Did not provide evidence tht it has the responsibilty and clear decision-mang authority in accordance with RI.

3.3. Level 

### 3: Not applicable.

Adopted by Board of Trustees: October 29, 2008 Effctive Date: May 13, 2009 

### Page40f13Standard EOP-002-2.1 - Capacity and Energy Emergencies

3.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the following requirements that is in violation: 3.4.1 Failed to communicate its current and future system conditions to its Reliability Coordinator and neighboring Balancing Authorities when in an operating Capacity or Energy Emergency (R3). 3.4.2 One or more of the actions of the Capacity and Energy Emergency Plans were not implemented as appropriate (R2). E. Regional Differences None identified. Version History

0 April 1, 2005 Effective Date New 0 August 8, 2005 Removed "Proposed" from Effective Errata Date I September 19, Changes R7. to refer to "Requirement 6" Errata

2006 instead of "Requirement 7" 2 November 1, Adopted by Board of Trustees Revised

,2006 2 November 1, Corrected numbering in Section A.4. Errata

2006 "Applicability. " 2 October 1, Added to Section 1 inadvertently Errata

2007 omitted "4.3. Load-Serving Entities 2.1 October 29, BOT adopted errata changes; updated Errata

2008 version number to "2.1 " 2.1 May 13, 2009 FERC Approved Revised

Adopted by Board ofTrustees: October 29. 2008 Effective Date: May 13, 2009 Page 50f13 Standard EOP-002-2.1 - Capacity and Energy Emergencies

3.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the following requirements that is in violation: 3.4.1 Failed to communicate its curent and futu system conditions to its

Reliabilty Coordinator and neighborig Balancing Authorities when in an operating Capacity or Energy Emergency (R3). 3.4.2 One or more of the actions of the Capacity and Energy Emergency Plan were not implemented as appropriate (R2). E. Regional Differences None identified. 

### Version History

0 April 1, 2005 Effective Date 

### New 0 

### August 8, 2005 Removed "Proposed" from Effective 

### Errta Date

1 September 19, Changes R 7. to refer to "Requirement 6" 

## Errta

2006 instead of "Requirement 7" 2 

### November 1, Adopted by Board of Trustees 

### Revised

,2006 2 

### November 1, Corrected numberig in Section A.4. 

## Errta

2006 

### "Applicabilty. " 2 October 1, Added to Section 1 invertently 

## Errta

2007 

### omitted "4.3. Load-Serving Entities 2.1 October 29, 

### BOT adopted errta changes; updated 

## Errta

2008 version number to "2.1 " 2.1 

### May 13, 2009 FERC Approved 

### Revised

Adopted by Board of Trustees: October 29, 2008 Efftive Date: May 13, 2009 Page 50f13Standard EOP-002-2.1 - Capacity and. Energy Emergencies

Attachment l-EOP-002-2.1 Energy Emergency Alerts

Introduction This Attachment provides the procedures by which a Load Serving Entity can obtain capacity and energy when it has exhausted all other options and can no longer provide its customers' expected energy requirements. NERC defmes this situation as an "Energy Emergency." NERC assumes that a capacity deficiency will manifest itself as an energy emergency. The Energy Emergency Alert Procedure is initiated by the Load Serving Entity's Reliability Coordinator, who declares various Energy Emergency Alert levels asdefined in Section B, "Energy Emergency Alert Levels," to provide assistance to the Load Serving Entity. The Load Serving Entity who requests this assistance is referred to as an "Energy Deficient Entity."NERC recognizes that Transmission Providers are subject to obligations under FERCapproved tariffs and other agreements, and nothing in these procedures should be interpreted as changing those obligations. A. General Requirements 1. Initiation by Reliability Coordinator. An Energy Emergency Alert may be initiated only by a Reliability Coordinator at 1) the Reliability Coordinator's own request, or 2) upon the request of a Balancing Authority, or 3) upon the request of a Load Serving Entity. 1.1. Situations for initiating alert. An Energy Emergency Alert may be initiated for the following reasons: • When the Load Serving Entity is, or expects to be, unable to provide its customers' .energy requirements, and has been unsuccessful in locating other systems with available resources from which to purchase, or • The Load Serving Entity cannot schedule the resources due to, for example, Available Transfer Capability (ATC) limitations or transmission loading relief limitations. 2. Notification. A Reliability Coordinator who declares an Energy Emergency Alert shall notify all Balancing Authorities and Transmission Providers in its Reliability Area. The Reliability Coordinator shall also notify all other Reliability Coordinators of the situation via the Reliability Coordinator Information System (RCIS). Additionally, conference calls between Reliability Coordinators shall be held as necessary to communicate system conditions. The Reliability Coordinator shall also notify the other Reliability Coordinators when the alert has ended. B. Energy Emergency Alert Levels
Introduction To ensure that all Reliability Coordinators clearly understand potential and actual energy emergencies in the Interconnection, NERC has established three levels of Energy Emergency
Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13, 2009 Page60f13 Standard EOP-002-2.1 - Capacity and. Energy Emergencies

Attchment l-EOP-002-2.1 

### Energy Emergency Alerts


### Introduction Ths Attchment provides the procedures by which a Load Serving Entity can obtain capacity and energy when it has exhausted all other options and can no longer provide its customers' 

### expected energy requirements. NERC dermes this sitution as an "Energy Emergency." NERC assumes that a capacity deficiency will manifest itself as an energy emergency. 

### The Energy Emergency Alert Procedure is intiated by the Load Servg Entity's Reliabilty Coordinator, who declares various Energy Emergency Alert levels asdefied in Section B, "Energy Emergency Alert Levels," to provide assistace to the Load Serving Entity. 

### The Load Servg Entity who requests this assistance is referred to as an "Energy Deficient Entity."NERC recognes that Trasmission Providers are subject to obligations under FERCapproved taffs and other agreements, and nothing in these procedures should be interpreted 

### as changing those obligations. 

### A. General Requirements 1. Initiation by Reliabilty Coordinator. An Energy Emergency Alert may be initiated 

### only by a Reliability Coordinator at 1) the Reliabilty Coordinator's own request, or 2) upon the request of a Balancing Authority, or 3) upon the request of a Load Serving Entity. 1.1. Situations for initiating alert. An Energy Emergency Alert may be intiated 

### for the followig reasons: 

### · When the Load Serving Entity is, or expects to be, unble to provide its customers' .energy requirements, and has been unuccessful in locating 

### other systems with available resources from which to purchase, or 

### · The Load Serving Entity canot schedule the resours due to, for example, Available Trafer Capabilty (ATC) limitations or trsmission loading relief limitations. 2. Notication. A Reliabilty Coordinator who declares an Energy Emergency Alert 

### shall notify all Balancing Authoritiès and Transmission Providers in its Reliabilty 

### Area. The Reliabilty Coordinator shal also notify all other Reliabilty Coordinators of the sitution via the Reliabilty Coordinator Inormation Systèm (RCIS). Additionally, conference calls between Reliabilty Coordinators shall be held as necessar to communcate system conditions. The Reliabilty Coordinator shall also 

### notify the other Reliabilty Coordinators when the alert has ended. 

### B. Energ Emergency Alert Levels 

### Introduction To ensure that all Reliabilty Coordinators clearly understand potential and actul energy

emergencies in the Interconnection, NERC has established thee levels of 

### Energy Emergency Adopt by Board of Trustees: October 29, 2008 Effecve Date: May 13, 2009 

### Page60f13Standard EOP-002·2.1 - Capacity and Energy Emergencies

Energy Deficient Entity and, if applicable, its Balancing Authority on the NERC website. 2.2 Declaration period. The Energy Deficient Entity shall update its Reliability Coordinator of the situation at a minimum of every hour until the Alert 2 is terminated. The Reliability Coordinator shall update the energy deficiency information posted on the NERC website as changes occur and pass this information on to the affected Reliability Coordinators, Balancing Authority, and Transmission Providers. 2.3 Sharing information on resource availability. A Balancing Authority and market participants with available resources shall immediately contact the Energy Deficient Entity. This should include the possibility of selling non-firm (recallable) energy out of available Operating Reserves. The Energy Deficient Entity shall notify the Reliability Coordinators of the results. 2.4 Evaluating and mitigating transmission limitations. The Reliability Coordinators shall review all System Operating Limits (SOLs) and Interconnection Reliability Operating Limits (IROLs) and transmission loading relief procedures in effect that may limit the Energy Deficient Entity's scheduling capabilities. Where appropriate, the Reliability Coordinators shall inform the Transmission Providers under their purview of the pending Energy Emergency and request that they increase their ATC by actions such as restoring transmission elements that are out of service, reconfiguring their transmission system, adjusting phase angle regulator tap positions, implementing emergency operating procedures, and reviewing generation redispatch options. 2.4.1 Notification of ATC adjustments. Resulting increases in ATCs shall be simultaneously communicated to the Energy Deficient Entity and the market via posting on the appropriate OASIS websites by the Transmission Providers. 2.4.2 Availability of generation redispatch options. Available generation redispatch options shall be immediately communicated to the Energy Deficient Entity by its Reliability Coordinator. 2.4.3 Evaluating impact of current transmission loading relief events. The Reliability Coordinators shall evaluate the impact of any current transmission loading relief events on the ability to supply emergency assistance to the Energy Deficient Entity. This evaluation shall include analysis of system reliability and involve close communication among Reliability Coordinators and the Energy Deficient Entity. 2.4.4 Initiating inquiries on reevaluating SOLs and IROLs. The Reliability Coordinators shall consult withthe Balancing Authorities and Transmission Providers in their Reliability Areas about the possibility of reevaluating and revising SOLs or IROLs. 2.5 Coordination of emergency responses. The Reliability Coordinator shall communicate and coordinate the implementation of emergency operating responses.

Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13, 2009 Page 8 of13 Standard EOP-002.2.1 - Capacity and Energy Emergencies


### Energy Deficient Entity and, if applicable, its Balancing Authority on the NERC website. 2.2 Declaration period. The Energy Deficient Entity shall update its Reliabilty

Coordinator of 

### the situation at a minimum of every hour until the Alert 2 is terminted. The Reliabilty Coordinator shall update the energy deficiency information posted on the 

### NERC website as changes occur and pass this inormtion on to the afected Reliabilty Coordinators, Balancing Authority, and Transmission Providers.

2.3 Sharig information on resource availabilty. A Balancing Authority and market 

### paricipants with available, resources shall immediately contact the Energy Deficient 

### Entity. This should include the possibilty of selling non-firm (recalable) energy out of available Operating Reserves. The Energy Deficient Entity shall notify the Reliabilty

Coordiators of the results. 

### 2.4 Evaluatig and mitigating transmission limitations. The Reliabilty Coordinators 

### shall review all System Operatig Limits (SOLs) and Interconnection Reliabilty

Operating Limts (IOLs) and trsmission loading relief 

### procedures in effect that may 

### limit the Energy Deficient Entity's scheduling capabilties. Where appropriate, the 

### Reliabilty Coordinators shall inorm the Transmission Providers under their puriew of the pending Energy Emergency and request that they increase their ATC by actions such 

### as restoring transmission elements that are out of service, reconfigung their trsmission system, adjustig phase angle regulator tap positions, implementing emergency operatig procedurs, and reviewing generation redispatch options.
2.4.1 Notication of ATC adjustments. Resulting increas in ATCs shall be simultaeously communcated to the Energy Deficient Entity and the market via posting on the appropriate OASIS websites by the Transmission Providers. 

### 2.4.2 Availabilty of generation redispatch options. Available generation repatch options shall be immediately communicated to the Energy Deficient Entity by its 

### Reliabilty Coordiator. 

### 2.4.3 Evaluatig impact of current transmission loading relief events. The 

### Reliabilty Coorditors shal evaluate the impact of any curent trmission loading relief events on the abilty to supply emergency assistace to the Energy 

### Deficient Entity. This evaluation shall include analysis of system reliabilty and involve close communication among Reliabilty Coorditors and the Energy Deficient Entity. 

### 2.4.4 Initiating inquiries on reevaluating SOLs and IROLs. The Reliabilty Coordiators shall consult with.the Balancing Authorities and Transmision Providers in their Reliabilty Areas about the possibilty of reevaluatig and revising SOLs or IROLs. 

### 2.5 Coordination of emergency responses. The Reliabilty Coordiator shall communcate and coordiate the implementation of emergency operating responses.

Adopted by Board of Trustees: October 29, 2008 Effctive Date: May 13, 2009 Page 8 of13Standard EOP-002-2.1 - Capacity and Energy Emergencies

2.6 Energy Deficient Entity actions. Before declaring an Alert 3, the Energy Deficient Entity must make use of all available resources. This includes but is not limited to: 2.6.1 All available generation units are on line. All generation capable of being on line in the time frame of the emergency is on line including quick-start and peaking units, regardless of cost. 2.6.2 Purchases made regardless of cost. All firm and non-firm purchases have been made, regardless of cost.2.6.3 Non-firm sales recalled and contractually interruptible loads and demandside management curtailed. All non-firm sales have been recalled, contractually interruptible retail loads curtailed, and demand-side management activated within provisions of the agreements. 2.6.4 Operating Reserves. Operating reserves are being utilized such that the Energy Deficient Entity is canying reserves below the required minimum or has initiated emergency assistance through its operating reserve sharing program. 3. Alert 3 - Firm load interruption imminent or in progress.
Circumstances: • Balancing Authority or Load Serving Entity foresees or has implemented firm load obligation interruption. The available energy to the Energy Deficient Entity, as determined from Alert 2, is only accessible with actions taken to increase transmission transfer capabilities. 3.1 Continue actions from Alert 2. The Reliability Coordinators and the Energy Deficient Entity shall continue to take all actions initiated during Alert 2. If the emergency has not already been posted on the NERC website (see paragraph 2.1), the respective Reliability Coordinators will, at this time, post on the website information concerning the emergency. 3.2 Declaration Period. The Energy Deficient Entity shall update its Reliability Coordinator of the situation at a minimum of every hour until the Alert 3 is terminated. The Reliability Coordinator shall update the energy deficiency information posted on the NERC website as changes occur and pass this information on to the affected Reliability Coordinators (via the RCIS), Balancing Authorities, and Transmission Providers. 3.3 Use of Transmission short-time limits. The Reliability Coordinators shall request the appropriate Transmission Providers within their Reliability Area to utilize available short-time transmission limits or other emergency operating procedures in order to increase transfer capabilities into the Energy Deficient Entity. 3.4 Reevaluating and revising SOLs and IROLs. The Reliability Coordinator of the Energy Deficient Entity shall evaluate the risks of revising SOLs and IROLs on the

Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13, 2009 Page 9 of13 Standard EOP-002-2.1 - Capacity and Energy Emergencies
2.6 Energy Deficient Entity actions. Before declarg an Alert 3, the Energy Deficient Entity must mae use of all available resources. This includes but is not limited to:

2.6.1 All available generation units are on line. All generation capable of being on

line in the time frame of 

### the emergency is on line including quick-sta and peakg units, regardless of cost. 2.6.2 Purchases made regardless of cost. All firm and non-firm purchases have been 

### made, regardless of cost.

### 2.6.3 Non-firm sales recalled and contractualy interruptible loads and demandside management curtiled. All non-fi sales have been recalled, contrctually interrptible retail loads curiled, and demand-side maagement activated within provisions of the agreements. 2.6.4 Operating Reserves. Operating reserves are being utilzed such that the Energy 

### Deficient Entity is caring reserves below the required miimum or has initiated 

### emergency assistace though its operating reserve sharng progrm.
3. Alert 3 - Firm load interruption imminent or in progress. 

### Circumstances:

. Balancing Authonty or Load Serving Entity foresees or has implemented firm load obligation interrption. The available energy to the Energy Deficient Entity, as determined from Alert 2, is only accessible with actions taken to increase trsmission trsfer 

### capabilties.

3.1 Contiue actions from Alert 2. The Reliabilty Coordinators and the Energy Deficient 

### Entity shall continue to tae all actions intiated dunng Alert 2. If the emergency ha not

already been posted on the NERC website (see parph 

### 2.1), the respective Reliability Coordinators wil, at this time, post on the website inormation concerng the 

### emergency. 3.2 Declaration Period. The Energy Deficient Entity shall update its Reliabilty Coordinator of the sitution at a minimum of every hour until the Alert 3 is termated. The Reliabilty Coordinator shall update the energy deficiency inormation poste on the 

### NERC website as changes occur and pass ths information on to the affected Reliabilty Coordinators (via the RCIS), Balancing Authonties, and Transmission Providers.

3.3 Use of Transmission short-tie limts. The Reliabilty Coordinators shall reuest the 

### appropnate Trasmission Providers with their Reliabilty Area to utilie available short-time trmission limits or other emergency operating procedures in order to increase trsfer capabilties into the Energy Deficient Entity. 3.4 Reevaluatig and revising SOLs and IROLs. The Reliabilty Coordinator of the 

### Energy Deficient Entity shal evaluate the nsks of revising SOLs and IROLs on the

Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13, 2009 Page 9 of13Standard EOP"()02·2.1 - Capacity and Energy Emergencies

reliability of the overall transmission system. Reevaluation of SOLs and IROLs shall be coordinated with other Reliability Coordinators and only with the agreement of the Balancing Authority or Transmission Operator whose equipment would be affected. The resulting increases in transfer capabilities shall only be made available to the Energy Deficient Entity who has requested an Energy Emergency Alert 3 condition. SOLs and IROLs shall only be revised as long as an Alert 3 condition exists or as allowed by the Balancing Authority or Transmission Operator whose equipment is at risk. The following are minimum requirements that must be met before SOLs or IROLs are revised: . 3.4.1 Energy Deficient Entity obligations. The deficient Balancing Authority or Load Serving Entity must agree that, upon notification from its Reliability Coordinator of the situation, it will immediately take whatever actions are necessary to mitigate any undue risk to the Interconnection. These actions may include load shedding. 3.4.2 Mitigation of cascading failures. The Reliability Coordinator shall use its best efforts to ensure that revising SOLs or IROLs would not result in any cascading failures within the Interconnection. 3.5 Returning to pre-emergency Operating Security Limits. Whenever energy is made available to an Energy Deficient Entity such that the transmission systems can be returned to their pre-emergency SOLs or IROLs, the Energy Deficient Entity shall notify its respective Reliability Coordinator and downgrade the alert. 3.5.1 Notification of other parties. Upon notification from the Energy Deficient Entity that an alert has been downgraded, the Reliability Coordinator shall notify the affected Reliability Coordinators (via the RCIS), Balancing Authorities, and Transmission Providers that their systems can be returned to their normal limits. 3.6 Reporting. Any time an Alert 3 is declared, the Energy Deficient Entity shall submit the report enclosed in this Attachment to its respective Reliability Coordinator within two business days of downgrading or termination of the alert. Upon receiving the report, the Reliability Coordinator shall review it for completeness and immediately forward it to the NERC stiff for posting on the NERC website. The Reliability Coordinator shall present this report to the Reliability Coordinator Working Group at its next scheduled meeting. 4. Alert 0 - Termination. When the Energy Deficient Entity believes it will be able to supply its customers' energy requirements, it shall request ofits Reliability Coordinator that the EEA be terminated. 4.1. Notification. The Reliability Coordinator shall notify all other Reliability Coordinators via the RCIS of the termination. The Reliability Coordinator shall also notify the affected Balancing Authorities and Transmission Operators. The Alert 0 shall also be posted on the NERC website ifthe original alert was so posted ..

Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13, 2009 Page 100f13 Standard EOP-002-2.1 - Capacity and Energy Emergencies

reliability of the overall trsmission system. Reevaluation of SOLs and IROLs shall be

coordinated with other Reliabilty Coordiators and only with the agreement of the 

### Balancing Authority or Tramission Operator whose equipment would be affected. The resulting increases in trnsfer capabilties shall only be made available to the Energy 

### Deficient Entity who has requested an Energy Emergency Alert 3 condition. SOLs and 

### IROLs shall only be revised as long as an Alert 3 condition exist or as allowed by the Balancing Authority or Transmission Operator whose equipment is at risk. The 

### following are mimum requiements that must be met before SOLs or IROLs are 

### revised: .

3.4.1 Energy Deficient Entity obliations. The deficient Balancing Authority or Load Servg Entity must agree tht, upon notification from its Reliability Coordinator

of 

### the sitution, it wil immediately tae whatever actions are necessa to mitigate any undue risk to the Interconnection. These actions may include load 

### sheddig. 3.4.2 Mitigation of cascading failures. The Reliabilty Coordinator shall use its best effort to ensure that revising SOLs or IROLs would not result in any cascading 

### failures withn the Interconnection.
3.5 Returnig to pre-mergency Operating Security Limits. Whenever energy is made 

### available to an Energy Deficient Entity such that the transmission systems can be retued to their pre-emergency SOLs or IROLs, the Energy Deficient Entity shall notify its respective Reliabilty Coordinator and downgr the alert.

3.5.1 Notification of other partes. Upon notification from the Energy Deficient 

### Entity that an alert has been downgrded, the Reliabilty Coordinator shall notify the affected Reliabilty Coorditors (via the RCIS), Balancing Authorities, and
Transmission Providers tht their systems can be retued to their normal limits. 3.6 Reportg. Any time an Alert 3 is declared, the Energy Deficient Entity shall submit the 

### report enclosed in this Attchment to its respectve Reliabilty Coordinator with two business days of downgrding or termation of the aler Upon receiving the report, the Reliabilty Coorditor shal review it for completeness and imediately forward it to

the NERC stff for, postg on the NERC website. The Reliabilty Coordiator shall 

### present this report to the Reliabilty Coordiator Working Group at its next scheduled 

### meetig. 4. Alert 0 - Termiation. When the Energy Deficient Entity believes it will be able to supply its customers' energy requirements, it shall request ofits Reliabilty Coordinator that the EEA be termated.

4.1. Notification. The Reliabilty Coordinator shall notify all other Reliabilty

Coordiators via the RCIS of 

### the termation. The Reliàbilty Coorditor shall also notify the affected Balacing Authorities and Tramission Operators. The 

### Alert 0 shall also be posted on the NERC website if the original alert was so posted. .

Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13, 2009 Page 100f13Standard EOP"()02·2.1 - Capacity and Energy Emergencies

C. Energy Emergency Alert 3 Report A Deficient Balancing Authority or Load Serving Entity declaring an Energy Emergency Alert 3 must complete the following report. Upon completion of this report, it is to be sent to the Reliability Coordinator for review within two business days of the incident. Requesting Balancing Authority:

Entity experiencing energy deficiency (if different from Balancing Authority):

Date/Time Implemented:

Date/Ttme Released:

Declared Deficiency Amount (MW):

Total energy supplied by other Balancing Authority during the Alert 3 period:

Conditions that precipitated call for "Energy Deficiency Alert 3":

H"Energy Deficiency Alert 3" had not been called, would firm load be cut? Hno, explain:

Explain what action was taken in each step to avoid calling for "Energy Deficiency Alert 3":

Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13, 2009 Page 11 of13 Standard EOP-002.2.1 - Capacity and Energy Emergencies

C. Energy Emergency Alert 3 Report 

### A Deficient Balancing Authority or Load Serving Entity declarg an Energy Emergency Alert 3

must complete the following report. Upon completion of 

### this report it is to be sent to the Reliabilty Coordinator for review within two business days of the incident. 

### Requestig Balancing Authority:



### Entity experiencing energy deficiency (ü different from Balancing Authority):



### Daterrime Implemented:

Daterrime Released:


### Declared Deficiency Amount (M:

Total energy supplied by other Balancing Authority during the Alert 3 period:

Conditions that precipitated call for "Energy Deficiency Alert 3":

H "Energ Deficiency Alert 3" had not been called, would firm load be cut? H no, explain:



### Explain what action was taken in each step to avoid callg for "Energy Deficiency Alert 3":

Adopted by Board of Trustees: October 29, 2008 Effctive Date: May 13, 2009 Page 11 of13Standard EOP-002·2.1 - Capacity and Energy Emergencies

1. All generation capable of being on line in the time frame of the energy deficiency was on line (including quick start and peaking units) without regard to cost.

2. All firm and nenflrm purchases were made regardless of cost.



# . ..

3. All nonfirm sales were recalled within provisions of the sale agreement.

4. Interruptible load was curtailed where either advance notice restrictions were met or the interruptible load was considered part of spinning reserve.

5. Available load reduction programs were exercised (public appeals, voltage reductions, ete.),

6. Operating Reserves being utilized.

Adopted by Board of Trustees: OCtober 29, 2008 Effective Date: May 13, 2009 Page 12 of13 Standard EOP-002.2.1 - Capacity and Energy Emergencies

1. Al generation capable of being on line in the time frame of the energy deficiency was on line (including quick start and peakig units) without regard to cost.

2. Al firm and nonfirm purchases were made regardless of cost.

...

3. All nonfirm sales were recalled within provisions of the sale agreement.

4. Interruptible load was curtailed where either advance notice restrctions

were met or the interruptible load was considered part of spinnig reserve.

5. Available load reduction programs were exercised (public appeals, voltage 

### reductions, etc.).

6. Operating Reserves being utied.

Adopted by Board of Trustee: OCober 29, 2008 Effective Date: May 13, 2009 Page 12 of13Standard EOP-002-2.1 - Capacity and Energy Emergencies

Comments:

Reported By: Organization: Title:

Adopted by Board of Trustees: October 29, 2008 Effective Date: May 13, 2009 Page 13 of 13 Standard EOP-002-2.1 - Capacity and Energy Emergencies



### Comments:

Reported By: 

### Title: 

### Organiztion:

Adopted by Board of Trustees: October 29, 2008 Effctive Date: May 13, 2009 Page 13 of 13

# Attachment 3

PJM Manual 13: Emergency Operations Attachment 3

PJM Manual 

# 13: Emergency Operations

## Copyrighted page/s removed. Copyrighted material is not available in Regulations.gov since it may not be reproduced without consent of the copyright holder. Contact the EPA Docket Center’s Public Reading Room to view or receive a copy of this document. Requests for copies may be made as follows: In person/writing: Environmental Protection Agency, Docket Center 1301 Constitution Ave NW, 2822T, Room 3334 Washington, DC. 20004 Telephone: 202-566-1744
Fax: 202-566- 9744
Email: docket-customerservice@epa.gov

# Attachment 4

PJM FERC Electric Tariff, Sixth Revised Volume No.1, PJM Emergency Load Response Program Attachment 4



# PJM FERC Electric Tariff, Sixth Revised Volume No.1, PJM Emergency Load Response 

# ProgramPJM Interconnection, L.L.C.

FERC Electric Tariff Sixth Revised Volume No.1 Substitute Original Sheet No. 414 

# ~JM Superseding Original Sheet No. 414 -, 

# f

# r~"",-
PJM Emergency Load Response Program

Issued By: Craig Glazer

Vice President, Governmental Policy Issued On: March 27, 2003 Effective: March 20, 2003 

### PlM Interconnection, L.L.C. 

### FERC Electrc Tarff Sixth Revised Volume NO.1 

## Substitute Orina Sheet No. 414 ~JM Superseding Original Sheet No. 414 -, f r~"" 

# PJM Emergency Load Response Program

Issued By: Craig Glazer



### Vice President, Governental Policy Issued On: March 27, 2003 

### Effective: March 20, 2003PJM Interconnection, L.L.C.

FERC Electric Tariff Sixth Revised Volume No.1 Substitute First Revised Sheet No. 415 Superseding First Revised Sheet No. 415 

# Table of Contents

EMERGENCY LOAD RESPONSE PROGRAM ••••••••••••••••••••••••••••••• 416
PARTICIPANT QUALIFiCATIONS ••••••••••••••••••••••••••••••••••••••••••••• 416
METERING REQUIREMENTS •••••••••••••••••••••••••••••••••••••••••••••••••• 417
REGiSTRATION ••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••• 

### 418

EMERGENCY OPERATIONS ••••••••••••••••••••••••••••••••••••••••••••••••••• 419
VERIFiCATION •••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••• 419A
MARKET SE"nLEMENTS ••••••••••••••••••••••••••••••••••••••••••••••••••••••• 

### 420
REPORT. NG ••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••• 421
NON-HOURLY METERED CUSTOMER PiLOT ••••••••••••••••••••••••••••• 421

Issued By: Craig Glazer Effective: Upon Implementation Date

Vice President, Federal Government Policy Issued On: March 27, 2006 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER06-406-000, issued February 24,2006,114 FERC ~ 61,201 (2006). PJM Interconnection, L.L.C. 

### FERC Electrc Tariff Sixth Revised Volume NO.1 Substitute First Revised Sheet No. 415 Superseding First Revised Sheet No. 415 

# Table of Contents

EMERGENCY LOAD RESPONSE PROGRAM ............................... 416 

### PARTICIPANT QUALIFiCATIONS.............................................416 METERING REQUIREMENTS .............. .................................... 417 

### REGiSTRATION...................................................................418 EMERGENCY OPERATIONS ................................................... 419 

### VERIFiCATION..................................................................419A MARKET SE"LEMENTS..... ...................... ............................ 420 REPORT. NO .. ... ... ...... .......... ......... ...... ...... ...... ... ..... .... .... .... 421 

### NON-HOURLY METERED CUSTOMER PiLOT............................. 421

# flD

Issued By: Craig Glaz Effective: Upon Implementation Date

Vice President, Federal Governent Policy Issued On: Mach 27, 2006 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. ER06-406-000, issud Febru 24,2006, 114 FERC ~ 61,201 (2006).P1MInterconnection, L.L.C.

FERC Electric Tariff Sixth Revised Volume No. 1 Substitute Third Revised Sheet No. 416 Superseding Third Revised Sheet No. 416



### EMERGENCY LOAD RESPONSE PROGRAM The Emergency Load Response Program is designed to provide a method by which end-use customers may be compensated by PJM for reducing load during an emergency event. There are two options for participation in the Emergency Load Response Program: • Full Program Option Participants in the Full Program Option receive an energy payment for load reductions during an emergency event and an Active Load Management ("ALM") credit pursuant to Schedule 5.2 of the Reliability Assurance Agreement, the Reliability Assurance Agreement-West, and the Reliability Assurance Agreement-South, as applicable. • Energy Only Option Participants in the Energy Only Option receive only an energy payment for load reductions during an emergency event. 

### PARTICIPANT QUALIFICATIONS Two primary types of distributed resources are candidates to participate in either of the two options provided by the Emergency Load Response Program: • On-Site Generators These generators (including Behind The Meter Generation) can be either synchronized or non-synchronized to the grid. Capacity Resources are not eligible for compensation under this program. Injections into the grid by local generators also will not be eligible for compensation under this program.
• Load Reduction A participant that has the ability to reduce a measurable and verifiable portion of its load, as metered on an EDC account basis.

Issued By: Craig Glazer Effective: Upon Implementation Date

Vice President, Federal Government Policy Issued On: March 27, 2006 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No.ER06-406-000, issued February 24, 2006, 114 FERC 

### 161,201 (2006). P 1M Interconnection, L.L. C. 

### FERC Electrc Tarff Sixth Revised Volume No. 1 Substitute Third Revised Sheet No. 416 Superseding Third Revised Sheet No. 416 

# 1tin

EMERGENCY LOAD RESPONSE PROGRAM The Emergency Load Response Program is designed to provide a method by 

### which end-use customers may be compensated by PJM for reducing load during an emergency event. There are two options for participation in the Emergency Load Response Program:
. Full Program Option 

### Participants in the Full Program Option receive an energy payment for load reductions durg an emergency event and an Active Load Management ("ALM") 

### credit pursuant to Schedule 5.2 of the Reliabilty Assuice Agreement, the Reliabilty Assurce Agreement-West, and the Reliabilty Assurce 

### Agreement-South, as applicable. . Energy Only Option 

### Participants in the Energy Only Option receive only an energy payment for load reductions durng an emergency event. 

## PARTICIPANT QUALIFICATIONS Two primary types of ,distributed resources are candidates to participate in either of the two options provided by the Emergency Load Response Program:
. On-Site Generators 

### These generators (including Behind The Meter Generation) can be either synchronied or non-synchronied to the grd. Capacity Resoures are not 

### eligible for compensation under this program Injections into the grd by local generators also will not be eligible for compensation under this program.
+ Load Reduction 

### A paricipant tht has the abilty to reduce a meaurble and verifiable porton of its load, as metere on an EDC account basis.



### Issued By: Craig Glaz Effective: Upon Implementation Date

Vice President, Federl Governent Policy Issued On: March 27, 2006 Filed to comply with order of the Federa Energy Regulatory Commission, Docket No.ER06-06-o00, issued Februar 24, 2006, 114 FERC 1 61,201 (2006).PlMInterconnection, L.L.C.

FERC Electric Tariff Sixth Revised Volume No. I Fourth Revised Sheet No. 417 Superseding Third Revised Sheet No. 417

PJM membership is required to participate in either of the two options provided by the Emergency Load Response Program. Members or Special Members may participate in the Emergency Load Response Program unless the laws or regulations of the Relevant Electric Retail Regulatory Authority expressly prohibit their participation. Special membership provisions have been established for program participants in the Energy Only Option, as described below. The special membership provisions shall not apply to program participants in the Full Program Option. Any existing PlM Member may act as a third party for non-members, in which case the third party will be referred to as the Curtailment Service Provider (CSP). All payments are made to the PJM Member. Participants must become signatories to the PJM Operating Agreement, as described in the PJM Manual/or Administrative Services/or the Operating Agreement of the PJM Interconnection, LL.C However, for special members the $5,000 annual membership fee, the $1,500 application fee, and liability for Member defaults are waived, along with the following other modifications:

Special Members are limited to be PJM market sellers; Voting privileges and sector designation are waived; Thirty day notice for waiting period is waived; Requirement for2417 control center coverage is waived; No PJM-supported user group capability is permitted. To participate in either of the two options provided by the Emergency Load Response Program, the distributed resource must:

Be capable of reducing at least 100 kW ofload Be capable of receiving PJM notification to participate during emergency conditions. To receive ALM Credits participants in the Full Program Option must satisfy the criteria set forth in Schedule 5.2 of the Reliability Assurance Agreement, the Reliability Assurance Agreement-West, and the Reliability Assurance Agreement-South, as applicable.


## METERING REQUIREMENTS

The Curtailment Service Provider is responsible to ensure that the Load Response Program Participants have metering equipment that provides integrated hourly kWh values on an electric distribution company account basis. The metering equipment shall either meet the electric distribution company requirements for accuracy or have a maximum error of two percent over the full range of the metering equipment (including Potential Transformers and Current Transformers) and the Issued By: Craig Glazer Effective: September 28, 2009

Vice President, Federal Government Policy Issued On: July 29, 2009 Sheet contains information from Third Revised Sheet No. 417, conditionally accepted, subject to compliance filing directed in PlMInterconnection, L.L.C., 128 FERC, 61,238 (2009). 

### PlM Interconnection, L.L.C. 

### FERC Electnc Tarff Sixth Revised Volume NO.1 Four Revised Sheet No. 417 Superseding Third Revised Sheet No. 417


### PlM membership is required to partcipate in either of the two options provided by the 

### Emergency Load Response Progrm. Members or Special Members may parcipate in the Emergency Load Response Progrm unless the laws or regulations of the Relevant 

### Electnc Retail Reguatory Authority expressly prohibit their parcipation. Special membership provisions have been established for progr paricipants in the Energy Only Option, as described below. The special membership provisions shall not apply to progr paricipants in the Full Program Option. Any existing P lM Member may act as 

### a third par for non-members, in which cae the thd par will be referred to as the Curilment Service Provider (CSP). All payments are made to the PJM Member. Participants must become signatories to the P JM Operating Agreement, as described in the PJM Manual/or Administrative Services/or the Operating Agreement o/the PJM Interconnectin, LL.C However, for special members the $5,000 annual membership 

### fee, the $1,500 application fee, and liabilty for Member defaults are waived, along with the following other modifications:



### Special Members are limted to be PJM market sellers; Voting privileges and sector designation are waived; 

### Thir day notice for waitig period is waived; Requirement for 24/7 control center coverage is waived; 

### No PJM-supportd user group capabilty is permtted. 

## To participate in either of the two options provided by the Emergency Load Response Program, the distributed resource must:

Be capable of 

### reducing at least 100 kW ofload 

### Be capable of receiving PlM notification to paricipate durng emergency conditions. 

### To receive ALM Credits parcipants in the Full Program Option must satisfy the criteria set 

### fort in Schedule 5.2 of the Reliabilty Assurce Agreement, the Reliabilty Assurce Agreement-West, and the Reliabilty Assuance Agreement-South, as applicable. 

## METERING REQUIREMENTS The Curaiment Service Provider is responsible to ensure that the Load 

## Response Program Paricipants have meterig equipment that provides integrated hourly kWh values on an electrc distribution company account basis. The mèterig equipment shall either meet the electric distribution company requiements for accuracy or have a maxium error of two 

### percent over the full range of the metering equipment (including Potential 

## Transformers and Current Transformers) and the Issued By: Craig Glazer Effective: September 28, 2009

Vice President, Federal Governent Policy Issued On: July 29, 2009 Sheet contains information from Third Revised Sheet No. 417, conditionaly accepted, subject to compliance filing directed in PlM Interconnection, L.L.C., 128 FERC' 61,238 (2009).PJM Interconnection, L.L.C.

FERC Electric Tariff Sixth Revised Volume No.1 

# Original Sheet No.

# 4l7Jf'E!,M

metering equipment and associated data shall meet the requirements set forth herein and in the PJM Manuals. The Emergency Load Response Participant must meter reductions in demand by using either of the following two methods: a) Using metering equipment that is capable of recording integrated hourly values for generation running to serve local load (net of that used by the generator); or

Issued By: Craig Glazer Effective: September 28, 2009

Vice President, Federal Government Policy Issued On: July 29, 2009 Sheet contains information from Third Revised Sheet No. 417, conditionally accepted, subject to compliance filing directed in PlM Interconnection. L.L.C., 128 FERC,. 61,238 (2009). 

### PlM Interconnection, L.L.C. 

### FERC Electrc Tarff Sixth Revised Volume No.1 

## Original Sheet No. 417Jf'El

metering equipment and associated data shal meet the requirements set forth herein and in the PJM Manuals. The Emergency Load Response 

### Participant must meter reductions in demand by using either of the following 

### two methods: 

## a) Using metering equipment that is capable of recording integrated hourly values for generation runnng to serve local load (net of that used by the generator); or



### Issued By: Craig Glazer Effective: September 28, 2009

Vice President, Federal Governent Policy Issued On: July 29, 2009 Sheet contain information from Third Revised Sheet No. 417, conditionally accepted, subject to compliance filing directed in PlM Interconnection, L.L.C., 128 FERC" 61,238 (2009).PlMInterconnection, L.L.C.

FERC Electric Tariff Sixth Revised Volume No.1 Second Revised Sheet No. 418 Superseding 2nd Rev Sub Original Sheet No. 418


### b) Using metering equipment that provides actual load change by measuring actual load before and after the reduction request, such that there is a valid integrated hourly value for the hour prior to the event and each hour during the event. This value cannot be estimated nor can it be averaged over some historical period. This..load will be metered on an electric distribution company account basis. Metered load reductions will be adjusted up to consider transmission and distribution losses as submitted by the Curtailment Service Provider and verified by PJM with the electric distribution company. The installed metering equipment must be one ofthe following: a) Metering equipment used for retail electric service; b) Customer-owned metering equipment or metering equipment acquired by the Curtailment Service Provider, approved by PJM, that is read electronically by PJM, in accordancewith the requirements herein and in the PJM Manuals; or c) Customer-owned metering equipment or metering equipment acquired by the Curtailment Service Provider, approved by PJM, that is read by the customer (or the Curtailment Service Provider), and such readings are then forwarded to PJM, in accordance with the requirements set forth herein and in the PJM Manuals. Nothing herein changes the existence of one recognized meter by the state commissionsas the officialbilling meter for recording consumption. 

## REGISTRATION Participants must complete the PJM Emergency Load Response Program Registration Form ("Emergency Registration Form") that is posted on the PJM web site (www.pjm.com).The followinggeneral steps will be followed: 1. The participant completes the Emergency Registration Form located on the PJM web site. PJM reviews the application and ensures that the qualifications are met, including verifying that the appropriate metering exists. PJM also confirms with the appropriate Load Serving Entity and electric distribution company whether the load reduction is under other contractual obligations, and with the electric distribution company

Issued By: Craig Glazer Effective: September 28, 2009

Vice President, Federal Government Policy Issued On: July 29, 2009 Sheet contains information from Second Revised Sub Original Sheet No. 418, conditionally accepted, subject to compliance filing directed in PJM Interconnection. L.L.C., 128 FERC ~ 61,238 (2009). 

### PlM Interconnection, L.L.C. 

### FERC Electrc Tarff Sixth Revised Volume No.1 Second Revised Sheet No. 418 Superseding 2nd Rev Sub Original Sheet No. 418 

## b) Using metering equipment that provides actual load change by measurng actual load before and after the reduction request, such that there is a valid integrated hourly value for the hour prior to the 

### event and each hour durng the event. This value cannot be estimated 

### nor can it be averaged over some historical period. This ..load wil be 

### metered on an electric distribution company account basis.
Metered load reductions wil be adjusted up to consider transmission and 

### distribution losses as submitted by the Curtailment Servce Provider and 

### veried by PJM with the electric distribution company. The installed meterig equipment must be one of the followig: 

### a) Metering equipment used for retail electric servce; b) Customer-owned metering equipment or metering equipment acquired 

## by the Curailment Servce Provider, approved by PJM, that is read electronically by PJM, in accordance with the requirements herein and 

### in the PJM Manuals; or 

### c) Customer-owned metering equipment or metering equipment acquired 

### by the Curtailment Servce Provider, approved by PJM, that is read by 

### the customer (or the Curailment Servce Provider), and such readings 

### are then forwarded to PJM, in accordance with the requirements set forth herein and in the PJM Manuals. Nothing herein changes the existence of one recognzed meter by the state 

### commissions as the offcial biling meter for recording consumption. 

## REGISTRATION Paricipants must complete the PJM Emergency Load Response Program Registration Form ("Emergency Registration Form") that is posted on the PJM web site (www.pjm.com). The following general steps will be followed:
1. The participant completes the Emergency Registration Form located 

## on the PJM web site. pJM reviews the application and ensures that the qualifcations are met, induding verifyig that the appropriate 

### metering exists. PJM also confrms with the appropriate Load Servg 

### Entity and electric distribution company whether the load reduction is 

### under other contractual obligations, and with the electric distribution company


### Issued By: Craig Glazer Effective: September 28, 2009

Vice President, Federal Governent Policy Issued On: July 29, 2009 Sheet contains infonnation from Second Revised Sub Onginal Shee No. 418, conditionally accepte, subject to compliance filing directed in PJM Interconnection. L.L.C., 128 FERC ~ 61,238 (2009).PJM Interconnection, L.L.C.

FERC Electric Tariff Sixth Revised Volume No.1 Original Sheet No. 418A



### whether the laws or regulations of the Relevant Electric Retail Regulatory Authority expressly prohibit the end-use customer's participation in PJM's EmergencyLoadResponseProgram pursuant to the process described below. Other such contractual obligations may not preclude participation in the program, but may require special consideration by PJM such that appropriate settlements are made within the confines of such existing contracts. The electric distribution company and Load Serving Entity have ten (10) business days to respond or PJM assumes acceptance. An electric distribution companywhich seeks to assert that the laws or regulations of the Relevant Electric Retail Regulatory Authority expressly prohibit an end-use customer's participation in PJM's Emergency Load Response program shall provide to PJM, within the referenced ten business day review period, either: (a) an order, resolution or ordinance of the Relevant Electric Retail Regulatory Authority expresslt; barring end-use customer participation, (b) an opinion of the Relevant Electric Retail Regulatory Authority's legal counsel attesting to the existence of a regulation or law expressly barring end-use customer participation, or (c) an opinion of the state Attorney General, on behalf of the Relevant Electric Retail Regulatory Authority, attesting to the existence of a regulation or law expressly barring end-use customer participation. PJM 

### may seek additional clarification, if necessary, from the Relevant Electric Retail Regulatory Authority and shall post on its web site all documentation submitted by an electric distribution company or Relevant Electric Retail Regulatory Authority to PJM 

### during the registration process pursuant to this section. .In the absence of a response from the electric distribution company or Load Serving Entity within the referenced ten business day period, the Office of the Interconnection shall assume that the load to be reduced is not subject to other contractual obligations or to laws or regulations of the Relevant Electric Retail Regulatory Authority that expressly prohibit the end-use customer's . participation in PJM's EmergencyLoadResponse Program.

Issued By: Craig Glazer Effective: September 28, 2009

Vice President, Federal Government Policy Issued On: July 29, 2009 Sheet contains information from Second Revised Sub Original Sheet No. 418, conditionally accepted. subject to compliance filing directed in PJM Interconnection. L.L.C., 128 FERC

### 1161,238 (2009). PJM Interconnection, L.L.C. 

### FERC Electrc Tariff Sixth Revised Volume No.1 Original Sheet No. 4l8A



### whether the laws or reguations of the Relevant Electric Retail Regulatory Authority expressly prohibit the end-use customer's 

### paricipation in PJM's Emergency Load Response Program pursuant to the process described below. Other such contractual obligations may 

## not preclude paricipation in the program, but may require special 

## consideration by PJM such that appropriate settlements are made within the confmes of such existing contracts. The electric distribution 

## company and Load Servng Entity have ten (10) business days to respond or PJM assumes acceptance. 

### An electric distribution company which seeks to assert that the laws or regulations of the Relevant Electric Retail Regulatory Authority expressly prohibit an end-use customer's parcipation in PJM's 

### Emergency Load Response program shall provide to PJM, within the referenced ten business day review period, either: (a) an order, resolution or ordiance of the Relevant Electric Retail Regulatory 

## Authority expresslt; barring end-use customer participation, (b) an opinion of the Relevant Electric Retai Regulatory Authority's legal counsel attesting to the existence of a regulation or law expressly 

### barrng end-use customer participation, or (c) an opinon of the state

Attorney General, on behalf of the Relevant 

### Electric Retail Regulatory 

### Authority, attesting to the existence of a reguation or law expressly 

## barrig end-use customer participation. PJM may seek additional clarcation, if necessary, from the Relevant Electric Retai Regulatory 

### Authority and shall post on its web site all documentation submitted 

### by an electric distribution company or Relevant Electric Retail Reguatory Authority to PJM during the registration process pursuant to this section. . In the absence of a response from the eleCtric distribution company or Load Servg Entity withi the referenced ten business day period, the Offce of the Interconnection shall assume that the load to be reduced is not subject to other contractual 

### obligations or to laws or regulations of the Relevant Electric Retai 

### Reguatory Authority that expressly prohibit the end-use customer's . participation in PJM's Emergency Load Response Program.



### Issued By: Craig Glazer Effective: September 28, 2009

Vice President, Federal Governent Policy Issued On: July 29, 2009 Sheet contains infonntion from Secnd Revised Sub Original Sheet No. 418, conditionaly accepted subject to compliance filing dircted in PJM Interconnection. L.L.C.. 128 FERC 11 61,238 (200).PJM Interconnection, L.L.C

FERC Electric Tariff Sixth Revised Volume No.1 First Revised Sheet No. 419A Superseding Original Sheet No. 419A



## VERIFICATION PJM requires that the load reduction meter data be submitted to PJM within 60 days of the event. If the data are not received within 60 days, no payment for participation is provided. Meter data must be provided for the hour prior to the event, as well as every hour during the event. These data files are to be communicated to PJM either via the Load ResponseProgram web site or email. Files that are emailed must be in the PJMapproved file format. Meter data will be forwarded to the EDe and LSE upon receipt, and these parties will then have ten (10) business days to provide feedback to PJM .

. Issued By: Craig Glazer Effective: June 29, 2009

Vice President, Federal Government Policy Issued On: Apri129, 2009 Filed to comply with Order No. 719 of the Federal Energy Regulatory Commission, Docket Nos. RM07- 19-00 and AD07-7-000, issued October 17, 2008,125 FERC 

### 161,071. 

### PJM Interconnection, L.L.C 

### FERC Electrc Tarff Sixth Revised Volume NO.1 First Revised Sheet No. 419A

Superseding Original Sheet 

### No. 4l9A



## VERIFICATION PJM requires that the load reduction meter data be submitted to PJM within 

### 60 days of the event. If the data are not received withi 60 days, no payment for participation is provided. Meter data must be provided for the hour prior to the event, as well as every hour during the event. 

### These data fies are to be communicated to PJM either via the Load ResponseProgram web site or emaiL. Fies that are emailed must be in the PJM

### approved file format. Meter data will be forwarded to the EDe and LSE upon receipt, and these parties will then have ten (10) business days to provide 

### feedback to PJM.



## . Issued By: Crag Glazer Effective: June 29, 2009

Vice President, Federa Goverent Policy

Issued On: April 29 , 2009
Filed to comply with Order No. 719 of the Federa Energy Reguatory Commssion, Docket Nos. RM07- 19-00 and AD07-7-000, issued October 17, 2008,125 FERC' 61,071.PJM Interconnection, L.L.C.

FERC Electric Tariff Sixth Revised Volume No.1 First Revised First Revised Sheet No. 420 Superseding First Revised Sheet No. 420 

# ~ .•..:M



# ltr~

MARKET SETTLEMENTS Payment for reducing load is based on the actual kWh relief provided plus the adjustment for losses. The minimum duration of a load reduction request is two hours. The magnitude of relief provided by Full Program Option participants shall be the amount PJM dispatches up to the kW amount declared on the Emergency Registration Form. The magnitude of relief provided by Energy Only Option participants could be less than, equal to, or greater than the kW amount declared on the EmergencyRegistration Form. PJM pays the applicable LMP to the PJM Member that nominates the load. Payment will be equal to the measured reduction (either measured output of backup generation or the difference between the measured load the hour before the reduction and each hour during the reduction) adjusted for losses times the applicable LMP. If, however, the sum of the hourly payments (excluding any ALM Credits) to a participant dispatched by PJM for actual, achieved reductions is not greater than or equal to the offer value (i.e. 

### Minimum Dispatch Price, minimum downtime and shut down costs)then the participant will be made whole up to the offer value for its actual, achieved reductions. Full Program Option participants that fail to provide a load reduction when dispatched by PJM shall be assessed the ALMDeficiencyCharge specified in Schedule 11 of the Reliability Assurance Agreement, the Reliability Assurance Agreement-West, and Reliability Assurance Agreement-South, as .applicable. During emergency conditions, costs for emergency purchases in excess of LMP are allocated among PJM Market Buyers in proportion to their increase in net purchases from the PJM energy market during the hour in the real time market compared to the day-ahead market. Consistent with this pricing methodology, all charges under this program are allocated to purchasers of energy, in proportion to their increase in net purchases from the PJM energy market during the hour from day-ahead to real time. Full Program Option participants that, prior to June 1, 2002, entered into contracts with LSEs or CSPs that enable participation in the Full Program Option, may participate in the Emergency Load Response program during ALM events as long as the customer's ALM contract explicitly excludes payment or credit for energy not consumed during ALMevents.

Issued By: Craig Glazer

Vice President, Federal Government Policy Issued On: December 28, 2005 Effective: February 24, 2006 

### PlM Interconnection, L.L.C. 

### FERC Electrc Tarff Sixth Revised Volume NO.1 First Revised First Revised Sheet No. 420 Superseding First Revised Sheet No. 420 

# ~....:M 

# ltr~

MARKET SETTLEMENTS Payment for reducing load is based on the actual kWh relief provided plus 

### the adjustment for losses. The minium duration of a load reduction request is two hours. The magntude of relief provided by Full Program Option participants shall be the amount PJM dispatches up to the kW amount 

## declared on the Emergency Registration Form. The magntude of relief provided by Energy Only Option participants could be less than, equal to, or greater than the kW amount declared on the Emergency Registration Form. 

### PJM pays the applicable LMP to the PJM Member that nominates the load. Payment will be equal to the measured reduction (either measured output of backup generation or the dierence between the measured load the hour 

### before the reduction and each hour durig the reduction) adjusted for losses 

## times the applicable LMP. If, however, the sum of the hourly payments (~xcluding any ALM Credits) to a participant dispatched by PJM for actual, 

## achieved reductions is not greater than or equal to the offer value (i.e. Minimum Dispatch Price, minimum down time and shut down costs) then the 

### participant wil be made whole up to the offer value for its actual, achieved reductions. 

### Full Program Option participants that fail to provide a load reduction when dispatched by PJM shall be assessed the AL Deficiency Charge specifed in 

### Schedule 11 of the Reliability Assurance Agreement, the Reliabilty Assurance Ageement-West, and Reliabilty Assurance Agreement-South, as , applicable. 

### Durng emergency conditions, costs for emergency purchases in excess of LMP are allocated among PJM Market Buyers in proportion to their increase 

## in net purchases frm the PJM energy market durg the hour in the real time market compared to the day-ahead market. Consistent with this pricing methodology, all charges under this program are allocated to purchasers of 

### energy, in proportion to their increase in net purchases from the PJM energy 

### market durng the hour from day-ahead to real time. 

## Full Program Option paricipants that, prior to June 1, 2002, entered into contracts with LSEs or CSPs that enable participation in the Full Progrm Option, may participate in the Emergency Load Response program durng ALM events as long as the customer's AL contract explicitly excludes payment or credit for energy not consumed during ALM events.

Issued By: Craig Glazer



### Vice President, Federal Governent Policy Issued On: December 28, 2005 

### Effective: Februar 24, 2006PlM Interconnection, L.L.C.

FERC Electric Tariff Sixth Revised Volume No.1 Fifth Revised Sheet No. 421 

# »mM Superseding Fourth Revised Sheet No. 421 ..

# r ~

# Ij __.__

If the LSE that submitted the Full Program Option participant for ALM credit indicates that such participant is not eligible for simultaneous credit under the Emergency Load Response program and ALM is called for concurrent with the Emergency Load Response program, then payments will be made to the participant according to the Emergency Load Response program only for the time during which ALM obligations were not in effect. Any response in excess of the contracted ALM amount will be compensated under the Emergency Load Response program for the entire duration of response. In the event that a Full Program Option participant entered into an ALM contract with an LSE that enables participation in the Full Program Option after June 1, 2002, such participant shall be credited for load reductions pursuant to this Emergency Load Response Program, notwithstanding any terms or conditions contrary in the contract; Program charges and credits will appear on the PJM Members monthly bill, as described in the PJM Manual for Operating Agreement Accounting and the PJM Manual for Billing. 

## REPORTING Actual load reductions of Energy Only Option emergency resources will be added back for the purpose of peak load calculations for capacity. Actual load reductions of Full Program Option and Capacity Only resources that have been registered as Emergency Load Response resources and/or Economic Load Response resources, and which occur from June 1 through September 30, will be added back for the purpose of calculating peak load for capacity. Capacity Only resources are Full Program Option resources that do not receive an energy payment for load reductions during an emergency event. Actual load reductions used for the purpose of calculating peak load for capacity, however, shall not exceed the quantity of kW committed and registered as Full Program Option or Capacity Only resources. PJM will submit any required reports to FERC on behalf of the Load Response Program participants. PJM will also post this document, as well as any other program-related documentation on the PJM web site. On an annual basis PJM will prepare a report that summarizes the status of the program and will submit it to the PJM Board of Managers, the Members Committee, the Reliability Committee, the Energy Market Committee, and the Operating Committee for review.

Issued By: Craig Glazer

Vice President, Federal Government Policy Issued On: March 4, 2009 Effective: June 1, 2009 

### PlM Interconnection, L.L.C. 

### FERC Electrc Tarff Sixth Revised Volume No. i 

### Fift Revised Shee No. 421 ,, RI Superseding Four Revised Sheet No. 421 .. r ~ Ij__.__ 

## If the LSE that submitted the Fu Program Option participant for AL credit indicates that such participant is not eligible for simultaneous credit under the Emergency Load Response program and AL is caled for 

### concurrent with the Emergency Load Response program, then payments wi be made to the participant according to the Emergency Load Response 

### program only for the time durig which ALM obligations were not in effect. 

### Any response in excess of the contracted ALM amount wi be compensated 

## under the Emergency Load Response program for the entire duration of response. 

### In the event that a Full Program Option participant entered into an ALM 

### contract with an LSE that enables paricipation in the Full Program Option after June i, 2002, such participant shall be credited for load reductions pursuant to this Emergency Load Response Program, notwithstanding any 

### terms or conditions contrary in the contract; 

### Program charges and credits wil appear on the PJM Members monthly bil, 

## as described in the PJM Manual for Operating Agreement Accounting and the PJM Manual for Billing. 

## REPORTING Actual load reductions of Energy Only Option emergency resources wil be added back for the purpose of peak load calculations for capacity. 

### Actual load reductions of Ful Program Option and Capacity Only resources that have been registered as Emergency Load Response resources and/or 

### Economic Load Response resources, and which occur from June i through September 30, wil be added back for the purpose of calculating peak load for 

### capacity. Capacity Only resources are Fu Program Option resources that do not receive an energy payment for load reductions during an emergency

event. Actual load reductions used for the purpose of calculatig peak load for 

## capacity, however, shall not exceed the quantity of kW committed and registered as Full Program Option or Capacity Only resources. 

## PJM will submit any requied reports to FERC on behalf of the Load Response Program participants. PJM wi also post this document, as well as any other program-related documentation on the PJM web site. 

### On an annual basis PJM will prepare a report that summarizes the status of the program and will submit it to the PJM Board of Managers, the Members 

### Committee, the Reliabilty Committee, the Energy Market Committee, and the Operating Committee for review.

Issued By: Craig Glazer



### Vice President, Federal Governent Policy Issued On: March 4, 2009 

### Effective: June 1, 2009PJM Interconnection, L.L.C.

FERC Electric Tariff Sixth Revised Volume No.1 Original Sheet No. 421A 

# *'BIM

NON-HOURLY METERED CUSTOMER PILOT Non-hourly metered customers may participate in the Emergency Load Response Program on a pilot basis under the following circumstances. The customer or its Curtailment Service Provider or Load Serving Entity must propose an alternate method for measuring hourly demand reductions. The Office of the Interconnection shall approve alternate measurement mechanisms on a case-by-case basis for a time period specified by the Office of the Interconnection ("Pilot Period"). In the event an alternative measurement mechanism is approved, the Office of the Interconnection shall notify the affected Load Serving Entity(ies) that a proposed alternate measurement mechanism has been approved for a Pilot Period.

Issued By: Craig Glazer

Vice President, Federal Government Policy March 4, 2009 Effective: June 1, 2009
Issued On: PJM Interconnection, L.L.C. 

### FERC Electrc Tarff Sixth Revised Volume No. i 

### Origi Sheet No. 421A l'BI



## NON-HOURLY METERED CUSTOMER PILOT Non-hourly metered customers may paricipate in the Emergency Load Response Progrm on a 

### pilot basis under the following circumstaces. The customer or its Curailment Service Provider 

### or Load Serving Entity must propose an alternate method for measurg hourly demand reductions. The Offce of the Interconnection shall approve alternate measuement mechanisms 

### on a case-by-case basis for a time period specified by the Offce of the Interconnection ("Pilot 

### Period"). In the event an alternative measurement mechansm is approved, the Offce of the Interconnection shall notify the affected Load Serving Entity(ies) that a proposed alternate measurement mechansm has been approved for a Pilot Period.

"..

Issued By: 

### Craig Glazer



### Vice President, Federal Governent Policy March 4, 2009 

### Effective: June i, 2009
Issued On:PlM Interconnection, L.L.C.

FERC Electric Tariff Sixth Revised Volume No. I First Revised Sheet No. 422 Superseding Substitute Original Sheet No. 422

Demand reductions by non-hourly metered customers using alternate measurement mechanisms on a pilot basis shall be limited to a combined total of 500 MW of reductions in both the Emergency Load Response Program and the PJM Interchange Energy Market. With the sole exception of the requirement for hourly metering, non-hourly metered customers shall be subject to the rules and procedures for participation in the Emergency Load Response Program. Following completion of a Pilot Period, the alternate method shall be evaluated by the Office of the Interconnection to determine whether such alternate method should be included in the PJM Manuals as an accepted measurement mechanism for demand reductions in the Emergency Load Response Program.

Issued By: Craig Glazer

Vice President, Federal Government Policy December 28, 2005 Effective: February 24, 2006
Issued On: 

### PlM Interconnection, L.L.C. 

### FERC Electrc Tariff Sixth Revised Volume No. 1 First Revised Sheet No. 422 Supersedg Substitute Original Sheet No. 422 

# 1tl!

Demand reductions by non-hourly metered customers using alternate measurement mechansms on a pilot basis shall be limited to a combined total of 500 MW of reductions in both the Emergency Load Response Program and the P JM Interchange Energy Market. With the sole exception of the requirement for hourly metering, non-hourly metered 

### customers shall be subject to the rules and procedures for parcipation in the Emergency 

### Load Response Program. Following completion of a Pilot Period, the alternate method shall be evaluated by the Offce of the Interconnection to determine whether such 

### alternate method should be included in the PlM Manuals as an accepted measurement mechansm for demand reductions in the Emergency Load Response Program.

Issued By: Craig Glazer



### Vice President, Federal Governent Policy December 28, 2005 

### Effective: Februry 24, 2006
Issued On:PJM Interconnection, L.L.C.

FERC Electric Tariff Sixth Revised Volume No.1 First Revised Sheet No. 423 Superseding Substitute Original Sheet No. 423


### [Sheet Nos. 423-444 Reserved For Future Use.]

Issued By: Craig Glazer

Vice President, Federal Government Policy Issued On: December 28, 2005 Effective: February 24, 2006 PJM Interconnection, L.L.C. 

### FERC Electrc Tanff Sixth Revised Volume NO.1 First Revised Sheet No. 423 Superseding Substitute Original Sheet No. 423

(Sheet Nos. 423-4 Reserved For Future Use.)

Issued By: Craig Glazer



### Vice President, Federal Governent Policy Issued On: December 28, 2005 

# rYlw

Effective: Febru 24, 2006

# Attachment 5

PJM Reliability Assurance Agreement Among Load Serving Entities in the PJM Region Condition, Rate Schedule FERC No. 44 

# Attachment 5



# PJM Reliability Assurance Agreement Among 

# Load Serving Entities in the PJM Region Condition, Rate Schedule FERC No. 44PlM Interconnection, L.L.C.

Rate Schedule FERC No. 44

RELIABILITY ASSURANCE AGREEMENT

Among



## LOAD SERVING ENTITIES

in the


## PJMREGION

K:\pjm\Current Effective Agreements\Stripped Current Effectives\PJM RAA Among LSEs (Rate Schedule FERC No. 44) 5-28-2009.doc 

### PlM Interconnection, L.L.C. Rate Schedule FERC No. 44



### RELIABILITY ASSURACE AGREEMENT

Among



## LOAD SERVIG ENTITIES

in the 

# PJMREGION

K:\pjm\Cunt Effective Agrements\Strppe Cuent EffectIves\PJM RA Among LSEs (Rate Schedule FERC No. 44) 5-28-2009.doc

# Attachment 6

ERCOT Protocols Section 5: Dispatch 

# Attachment 6



# ERCOT Protocols 

# Section 5: Dispatch

## ERCOT Protocols Section 5: Dispatch
January 1, 2010

PUBLIC 

# ERCOT Protocols 

# Section 5: Dispatch
January 1, 2010

PUBLICSECTION 5: DISPATCH

term inability to meet minimum TSP or DSP reactive requirements shall be immediately reported to ERCOT by way of the TSP.

5.6 Emergency and Short Supply Operation

5.6.1 Introduction ERCOT, as the single Control Area Operator, is responsible for maintaining reliability in normal and emergency operating conditions. The Operating Guides are intended to ensure that minimum standards for reliability are maintained. Minimum standards for reliability are defined by the Operating Guides and the North American Electric Reliability Corporation (NERC) standards and include, but are not limited to: (1) (2) (3) (4) (5) Minimum operating reserve levels; Criteria for determining acceptable operation of the frequency control system; Criteria for determining and maintaining system voltages within acceptable limits; Criteria for maximum acceptable transmission equipment loading levels; and Criteria for determining when ERCOT is subject to unacceptable risk of widespread cascading outages. In implementing these Protocols, ERCOTshall, to the fullest extent practicable, utilize market tools as prescribed in these Protocols before implementing command and control actions, such as OOMC, OOME, or RMR Service. It is anticipated that, with effective and timely communication, the tools available to ERCOT from the market will avert most threats to the reliability of the ERCOT System. However, these Protocols shall not preclude ERCOT from taking other actions to preserve the integrity of the ERCOT System.

5.6.2 Communication Good, accurate, and timely communication between ERCOT, msps, and QSEs is essential. The QSEs must be provided adequate information to make informed decisions and must receive the information with sufficient advance notice to facilitate generation and/or Load responses. The type of communication ERCOT will issue will be determined primarily on the basis of the time available for the market to respond before an Emergency Condition occurs. The timing of these communications could range from days in advance to immediate. If there is insufficient time to allow the market to react, ERCOT may bypass one or more of the communication steps. ERCOT shall consider the severity of the potential Emergency Condition as it determines which of the communications set forth in Section 5.6.3, Operating Condition Notice, through Section 5.6.6, Emergency Notice, to use. The severity of the Emergency Condition may be limited to an isolated local area affecting a small number of megawatts, or cover large areas affecting several
ERCOTPROTOCOLS -JANUARY 1,2010 5-8 PUBLIC SECTION 5: DISPATCH tenn inability to meet minimum TSP or DSP reactive requirements shall be immediately reported

to ERCOT by way of the TSP.

5.6 Emergency and Short Supply Operation

5.6.1 Introduction 

### ERCOT, as the single Control Area Operator, is responsible for maintaining reliabilty in nonnal and emergency operating conditions. The Operating Guides are intended to ensure that minimum standads for reliabilty are maintained. Minimum stadads for reliabilty are defined 

### by the Operating Guides and the Nort American Electrc Reliabilty Corpration (NERC) stadards and include, but are not limited to: (1) (2) (3) (4) (5) Minimum operating reserve levels;

Criteria for detennining acceptable operation of the frequency control system; Criteria for detennining and maintaining system voltages within acceptable limits; Criteria for maximum acceptable transmission equipment loading levels; and

Criteria for detennining when ERCOT is subject to unacceptable risk of 

### widespread cascading outages. 

### In implementing these Protocols, ERCOTshall, to the fullest extent practicable, utilze market tools as prescribed in these Protocols before implementing command and control actions, such as 

### OOMC, OOME, or RM Service. It is anticipated that, with effective and timely 

### communication, the tools available to ERCOT frm the market wil avert most threats to the

reliabilty of the ERCOT System. However, these Protocols shall not preclude ERCOT from 

### taking other actions to presrve the integrty of the ERCOT System.

5.6.2 Communication 

### Good, accurte, and timely communication between ERCOT, msps, and QSEs is essential. The QSEs must be provided adequate infonnation to make infonned decisions and must receive the 

### infonnation with suffcient advance notice to faciltate generation and/or Load responses.

The ty of communication ERCOT wil issue wil be detennined primaily on the basis of 

### the time available for the market to respond before an Emergency Condition occurs. The timing of

these communications could range from days in advance to imediate. If 

### there is insuffcient
time to allow the market to react, ERCOT may bypass one or more of 

### the communication steps.

ERCOT shall consider the severity of 

### the potential Emergency Condition as it detennines which

of 

### the communications set fort in Section 5.6.3, Operating Condition Notice, though Section

5.6.6, Emergency Notice, to use. The severity of 

### the Emergency Condition may be limited to an 

### isolated local ara affecting a small number of megawatt, or cover large areas affecting several

ERCOT PROTOCOLS -JANUARY 1,2010 5-8 PUBLICSECTION 5: DISPATCH

hundred megawatts, or may be an ERCOT -wide condition potentially affecting all of the ERCOT Region. The following sections describe the types of communications that will be issued by ERCOT to inform all QSEs and TDSPs of the operating situation. These communications may relate to transmission, distribution, and/or generation. The communications shall specify the severity of the situation, the area affected, the areas potentially affected, and the anticipated duration of the Emergency Condition.
5.6.3 OperatingConditionNotice ERCOT will issue an Operating Condition Notice (OCN) to inform all QSEs of a possible future need for more Resources due to conditions that could affect ERCOT System reliability. OCNs are for informational purposes only, and ERCOT exercises no extra operational authority with the issuance of this type of notice, but may solicit additional information from QSEs in order to determine whether the issuance of an Advisory, Watch, or Emergency Notice is warranted. When time permits, ERCOTwill issue an OCN before issuing an Advisory, Watch, or Emergency Notice. However, issuance of an OCN may not require action on the part of any Market Participant, but rather simply serves as a reminder to QSEs and TDSPs that some attention to the changing condition may be warranted. OCNs serve to communicate to QSEs the need to take extra precautions to be prepared to serve the Load during times when contingencies are most likely to arise. Reasons for OCNs include unplanned transmission outages, and weather related concerns such as anticipated freezing temperatures, hurricanes, wet weather, and ice storms. ERCOT will monitor actual and forecasted weather for ERCOT and adjacent NERC regions. When adverse weather conditions are expected, ERCOT may confer with TDSPs and QSEs regarding the potential for adverse reliability impacts and contingency preparedness. Based on its assessment of the potential for adverse conditions, ERCOT may require information from QSEs representing Resources regarding their fuel capabilities. Requests for this type of information shall be for a time period of no more than seven (7) days from the date of the request. The specific information which may be requested shall be defined in the Operating Guides. QSEs representing Resources shall provide the requested information in a timely manner, as defined by ERCOT at the time of the request. QSEs and TDSPs are expected to establish and maintain internal procedures for monitoring actual and forecasted weather and for implementing appropriate measures when the potential for adverse weather or other conditions (which could threaten ERCOT System reliability) arise.

ERCOT PROTOCOLS -JANUARY 1,2010 5·9 PUBLIC SECTION 5: DISPATCH hundred megawatts, or may be an ERCOT -wide condition potentially affecting all of thé ERCOT Region. 

### The following sections describe the types of communications that wil be issued by ERCOT to

inform all QSEs and TDSPs of the operating situation. These communications may relate to 

### trnsmission, distribution, and/or generation. The communications shall specify the severity of the sitution, the area affected, the aras potentially affected, and the anticipated duration of the Emergency Condition.

5.6.3 Operating Condition Notice 

### ERCOT wil issue an Operating Condition Notice (OCN) to inform all QSEs of a possible futue need for more Resources due to conditions that could affect ERCOT System reliabilty. OCNs are for informational purses only, and ERCOT exercises no extr operational authority with the issuance of this type of notice, but may solicit additional information from QSEs in order to determine whether the issuace of an Advisory, Watch, or Emergency Notice is warnted. 

### When time permits, ERCOTwil issue an OCN before issuing an Advisory, Watch, or Emergency Notice. However, issuance of an OCN may not require action on the pa of any 

### Market Participant, but rather simply serves as a reminder to QSEs and TDSPs that some 

### attntion to the changing condition may be warrnted. OCNs serve to communicate to QSEs the nee to take extr precautions to be prepared to serve the Load during times when contingencies ar most likely to arse. 

### Reasons for OCNs include unplaned trnsmission outages, and weather related concerns such as anticipated freezing temperatures, hurricaes, wet weather, and ice storms. 

### ERCOT wil monitor actul and forecasted weather for ERCOT and adjacent NERC regions. When adverse weather conditions are expected, ERCOT may confer with TDSPs and QSEs 

### regarding the potential for adverse reliabilty impacts and contingency preparedness. Based on 

### its assessment of the potential for advers conditions, ERCOT may require information frm QSEs representing Resources regarding their fuel capabilties. Request for this tye of information shall be for a time period of no more than seven (7) days from the date of the 

### request. The specific information which may be requested shall be defined in the Operating Guides. QSEs representing Resources shall provide the requested information in a timely manner, as defined by ERCOT at the time of the request. QSEs and TDSPs are expected to establish and maintain internal procedures for monitoring 

### actul and forecasted weather and for implementing appropriate measures when the potential for 

### adverse weather or other conditions (which could threaten ERCOT System reliabilty) arse.

ERCOT PROTOCLS -JANUARY 1,2010 5.9 PUBLICSECTION 5: DISPATCH

5.6.4 Advisory EReOT will issue an Advisory for informational purposes for the following reasons: (1) When it recognizes that conditions are developing or have changed and more Ancillary Services will be needed to maintain current or near-term operating reliability; (2) When weather or EReOT System conditions require more lead-time than the normal Day Ahead market allows; (3) When communications or other controls are significantly limited; or (4) When EReOT Transmission Grid conditions are such that operations within first contingency criteria as defmed in the Operating Guides are not likely or possible because of Forced Outages or other conditions. The Advisory communicates existing constraints. EReOT will notify TDSPs and QSEs. QSEs will notify appropriate Resources and LSEs. EReOT will communicate with TDSPs as needed to confirm their understanding of the condition and to determine the availability of Transmission Facilities. For the purposes of verifying submitted information, EReOT may communicate with QSEs. Although an Advisory is for information purposes, EReOT may exercise its authority, in such circumstances, to increase Ancillary Service requirements above the quantities specified in the normal Day Ahead plan in accordance with scheduling procedures. EReOT may also increase the Day Ahead market to Two Days Ahead. EReOT may require information from QSEs representing Resources regarding their fuel capabilities. Requests for this type of information shall be for a time period of no more than seven (7) days from the date of the request. The specific information which may be requested shall be defined in the Operating Guides. QSEs representing Resources shall provide the requested information in a timely manner, as defined by EReOT at the time of the request If the Advisory is the result of a short supply situation, each QSE with extra generating capacity that is normally not readily available due to ramp rate limitations (e.g., extra capacity on combined-cycle combustion turbines utilizing duct firing), may update their Up Balancing bid curve to reflect the extra capacity that can be made available in thirty (30) minutes or less. To prevent the deployment of such extra capacity, the HSL shall be adjusted down to a level equal to the HOL rating of the online Resource minus the amount of extra capacity bid into the Up Balancing minus the Ancillary Services obligation.

5.6.5 Watch
EReOT will issue a Watch when EReOT determines: (I) That conditions have developed such that additional Ancillary Services are needed in the Operating Period;

ERCOTPROTOCOLS-JANUARY 1,2010 5-10 PUBLIC SECTION 5: DISPATCH 5.6.4 Advisory 

### ERCOT wil issue an Advisory for informational purpses for the following reasons: 

### (1) When it recognizes that conditions are developing or have changed and more Ancilar Services will be needed to maintain current or near-term operating reliabilty; 

### (2) When weather or ERCOT System conditions require more lead-time than the normal Day Ahead market allows; 

### (3) When communications or other controls are significantly limited; or 

### (4) When ERCOT Trasmission Grid conditions are such that operations within first contingency criteria as defined in the Operating Guides are not likely or possible because

of Forced Outages or other conditions. 

### The Advisory communicates existing constrnts. ERCOT will notify TDSPs and QSEs. QSEs wil notify appropriate Resources and LSEs. ERCOT wil communicate with TDSPs as needed 

### to confirm their understanding of the condition and to determine the availabilty of Tramission

Facilties. For the purpses of 

### verifying submitted informtion, ERCOT may communcate with QSEs. 

### Although an Advisory is for information purses, ERCOT may exercise its authority, in such circumstaces, to increase Ancilary Service requirements above the quantities specified in the normal Day Ahead plan in accordace with scheduling procedures. ERCOT may also increase the Day Ahead market to Two Days Ahead. ERCOT may require information from QSEs 

### representing Resources regarding their fuel capabilties. Requests for this type of information shall be for a time period of no more than seven (7) days from the date of the request. The 

### specific informtion which may be requested shall be defined in the Operating Guides. QSEs representing Resources shall provide the requested information in a timely maner, as defined by ERCOT at the time of the request

If the Advisory is the result of a short supply sitution, each QSE with exta generating capacity that is normally not readily available due to rap rate limitations (e.g., extra capacity on combined-cycle combustion tubines utilzing duct firig), may updte their Up Balancing bid 

### cure to reflect the extra capacity that ca be made available in thir (30) minutes or less. To prevent the deployment of such extr capacity, the HSL shall be adjusted dówn to a level equal

to the HOL rating of 

### the online Resource minus the amount of extr capacity bid into the Up 

### Balancing minus the Ancilar Servces obligation.



### 5.6.5 Watch ERCOT wil issue a Watch when ERCOT determines:

(I) That conditions have developed such that additional Ancilary Services ar needed in the Operating Period;

ERCOTPROTOCOLS-JANUARY 1,2010 5-10 PUBLICSECfION 5: DISPATCH

(2) That market Congestion Management techniques specified in these Protocols will not be adequate to resolve transmission problems; or (3) Forced Outages or other abnormal operating conditions occur which require operations outside first contingency security limits as defined in the ERCOT Operating Guides; (4) That there are insufficient Ancillary Service bids. ERCOTwill post the Watch electronically and will notify all TDSPs and QSEs via the Messaging System of the posted Watch(es). ERCOT must issue a Watch before acquiring Emergency Short Supply Regulation Services (RGS), Emergency Short Supply Responsive Reserve Services (RRS) or Emergency Short Supply Non-Spinning Reserve Services (NSRS). With the issuance of a Watch pursuant to item (1) or (4) above, ERCOT may exercise its authority to immediately procure the following services from existing bids: (1) RGS; (2) RRS; and (3) NSRS. Emergency Short Supply RGS, Emergency Short Supply RRS or Emergency Short Supply NSRS will be procured if there is insufficient availability of bids for any of the listed Ancillary Services. ERCOT will post the Watch electronically on the Market Information System (MIS) and will notify all TDSPs and QSEs via the Messaging System of the posted Watch(es). Corrective actions identified by ERCOT shall be communicated through Dispatch Instructions to TDSPs and/or QSEs required to implement the corrective action. Each QSE shall immediately notify the Market Participants that it represents of such Watch. To minimize the effects on the ERCOT System, all TDSPs will identify and prepare to implement actions, including restoring outaged lines as appropriate and preparing for Load shedding. ERCOT may instruct·TDSPs to recorifigure ERCOT System elements as necessary to improve the reliability of the ERCOT System. On notification of a Watch, each QSE and TDSP will prepare for an emergency in case conditions worsen. ERCOT may require information from QSEs representing Resources regarding their fuel capabilities. Requests for this type of information shall be for a time period of no more than seven (7) days from the date of the request. The specific information which may be requested shall be defined in the Operating Guides. QSEs representing Resources shall provide the requested information in a timely manner, as defined by ERCOT at the time of the request.

ERCOTPROTOCOLS-JANUARY 1,2010 5·11 PUBLIC SECTION 5: DISPATCH 

### (2) That market Congestion Management techniques specified in these Protocols wil not be adequate to resolve transmission problems; or

(3) Forced Outages or other abnormal operating conditions occur which require operations outside first contingency security limits as defined in the ERCOT Operating Guides;

(4) That there are insuffcient Ancilary Service bids. 

### ERCOTwil post the Watch electronically and wil notify all TDSPs and QSEs via the

Messaging System of the posted Watch(es). ERCOT must issue a Watch before acquiring Emergency Short Supply Regulation Services 

### (RGS), Emergency Short Supply Responsive Reserve Services (R) or Emergency Short Supply Non-Spinning Reserve Services (NSRS). With the issuance of a Watch pursuat to item 

### (1) or (4) above, ERCOT may exercise its authority to immediately proure the following services from existing bids: 

### (1) RGS;
(2) RRS; and 

### (3) NSRS. Emergency Short Supply RGS, Emergency Short Supply RR or Emergency Short Supply

NSRS wil be procured if there is insuffcient availabilty of bids for any of 

### the listed Ancilary Services. ERCOT wil post the Watch electrnically on the Market Informtion System (MIS) and will

notify all TDSPs and QSEs via the Messaging System of the posted Watch(es). 

### Corrctive actions identified by ERCOT shall be communicated through Dispatch Instructions to 

### TDSPs and/or QSEs require to implement the corrective action. Each QSE shall immediately 

### notify the Market Paricipats that it represents of such Watch. To minimize the effects on the ERCOT System, all TDSPs wil identify and prepare to implement actions, including restoring 

### outaed lines as appropriate' and preparing for Load shedding. ERCOT may instrct.TDSPs to recorifigure ERCOT System elements as necessar to improve the reliabilty of the ERCOT System. On notification of a Watch, each QSE and TDSP wil prepare for an emergency in cas 

### conditions worsen. ERCOT may require information from QSEs representing Resources regarding their fuel capabilties. Reuests for this ty of information shall be for a time period

of no more than seven (7) days from the date of the request. The specifc information which may be reuested shall be defined in the Operating Guides. QSEs representing Resourcs shall

provide the reuested information in a timely maner, as defmed by ERCOT at the time of the 

### request

ERCOTPROTOCOLS-JANUARY 1,2010 5.11 PUBLICSECTION 5: DISPATCH

5.6.6 EmergencyNotice ERCOT will issue an Emergency Notice only for the following reasons: 0) ERCOT cannot maintain minimum reliability standards (for reasons including fuel shortages) during the Operating Period using every Resource practicably obtainable from the market; (2) ERCOT is in an unreliable condition, as defined below; (3) Immediate action must be taken to avoid orrelieve an overloaded transmission element; or (4) ERCOT varies from timing requirements or omits one or more scheduling procedures, as described in Section 4.8, Temporary Deviations from Scheduling Procedures. The actions EReOT takes during an Emergency Condition will depend on the nature and severity of the situation.
ERCOT is considered to be in an unreliable condition whenever ERCOT Transmission Grid status is such that the most severe single-contingency event presents the threat of uncontrolled separation or cascading outages and/or large-scale service disruption to Load (other than Load being served from radial transmission service) and/or overload of a critical transmission element, and no timely solution is obtainable from the market. If the Emergency Condition is the result of a transmission problem that puts ERCOT in an unreliable condition, then ERCOT will act immediately to return ERCOT to a reliable condition, including instructing Resources to change output and instructing TDSPs to drop Load. If the Emergency Condition is the result of a short supply situation, each QSE having bid extra capacity during the Advisory period that is normally not readily available due to ramp rate limitations, will immediately update their HSL of any online Resource that is capable of providing extra capacity within thirty (30) minutes. The HSL shall be set to equal the HOL rating of the online Resource minus the Ancillary Services Obligation. The extra capacity must already be part of the QSE's Up Balancing bid curve in order for Scheduling, Pricing and Dispatch (SPD) to utilize the updated HSL. If the short supply Emergency Condition continues, then the Energy Emergency Alert (EEA) procedures will be followed.



### 5.6.6.1 Energy Emergency Alert (EEA) At times it may be necessary to reduce electrical Demand because of a temporary decrease in available electricity supply. To provide orderly, predetermined procedures for curtailing Demand during such emergencies, ERCOT will initiate and coordinate the implementation of the EEA following the EEA levels set forth below in Section 5.6.7, EEALevels.

ERCOTPROTOCOLS-JANUARY 1,2010 5-12 PUBLIC SECTION 5: DISPATCH 5.6.6 Emergency Notice 

### ERCOT wil issue an Emergency Notice only for the following reasons: 

### (I) ERCOT canot maintain minimum reliabilty standards (for reasons including fuel

shortges) during the Operating Period using every Resource practicably obtainable from the market; 

### (2) ERCOT is in an unreliable condition, as defined below; (3) Immediate action must be taken to avoid orrelieve an overloaded transmission element; or 

### (4) ERCOT varies from timing requirements or omits one or more scheduling procedures, as described in Section 4.8, Tempora Deviations from Scheduling Procedures. 

### The actions ERCOT taes during an Emergency Condition will depend on the nature and

severity of the situation. 

### ERCOT is considered to be in an unreliable condition whenever ERCOT Trasmission Grid sttu is such that the most severe single-contingency event presents the threat ofuncontrolled separtion or cascading outages and/or large-scale service disruption to Load (other than Load 

### being served frm raial trmission service) and/or overload of a critical trsmission element, and no timely solution is obtainable from the market. If the Emergency Condition is the result of a trasmission problem that puts ERCOT in an 

### uneliable condition, then ERCOT will act immediately to return ERCOT to a reliable condition, including inscting Resources to change output and instrcting TDSPs to drop Load. 

### If the Emergency Condition is the result of a short supply situation, each QSE having bid extr 

### cacity during the Advisory period that is normally not readily available due to ramp rate limitations, wil immediately update their HSL of any online Resource tha is capable of providing exta capacity within th (30) minutes. The HSL shall be set to equal the HOL 

### rating of the online Resource minus the Ancilar Services Obligation. The exta capacity mus

alredy be par of the QSE's Up Balancing bid cure in order for Scheduling, Pricing and 

### Dispatch (SPD) to utilze the updated HSL.

If the short supply Emergency Condition continues, then the Energy Emergency Alert (EEA) procedurs wil be followed.

5.6.6.1 

### Energ Emergency Alert (EEA) At times it may be necessary to reduce electrical Demand because of a tempora decrease in 

### available electricity supply. To provide orderly, predetermined procedures for curtilng

Demand during such emergencies, ERCOT wil initiate and coordinate the implementation of 

### the EEA following the EEA levels set fort below in Section 5.6.7, EEALevels.

ERCOTPROTOCOLS-JANUARY 1,2010 5-12 PUBLICSECTION 5: DISPATCH

The objective of the EEA is to provide for maximum possible continuity of service while maintaining the integrity of the ERCOT Transmission Grid in order to reduce the chance of cascading outages. ERCOT's operating procedures shall meet the following goals while continuing to respect the confidentiality of market sensitive data: (I) Use of the market to the fullest extent practicable without jeopardizing the reliability of the ERCOT System; (2) Use of Responsive Reserve Services and other Ancillary Services to the extent permitted by ERCOT System conditions; (3) Maximum use ofERCOT System capability; (4) Maintenance of station service for nuclear Generation Resource Facilities; (5) Securing of startup power for Generation Resources; (6) Operation of power Generation Resources during loss of communication with ERCOT; (7) Restoration of service to critical Loads in the manner defined in the Operating Guides; and (8) Restoration of service to all Customers following major system disturbances, giving priority to the larger groups of Customers. ERCOT shall be responsible for coordinating with QSEs and TDSPs to monitor system conditions, initiating the EEA levels, notifying all QSEs, and coordinating the implementation of the EEA levels while maintaining transmission security limits. ERCOT, at management's discretion, may at any time issue an ERCOT-wide appeal through the public news media for voluntary energy conservation. During the EEA, ERCOT has the authority to obtain energy from Direct Current (DC) Ties or Block Load Transfers (BLTs) from non-ERCOT Control Areas when capacity is available. Some of the EEA levels will not be applicable if transmission security violations exist. There may be insufficient time to implement all levels in sequence, but to the extent practicable, ERCOT will use Ancillary Services which bidders have made available in the market to maintain or restore reliability. ERCOT may immediately implement EEA Level 3 any time the steady-state system frequency is below 59.8 Hz and will immediately implement EEA Level 3 any time the steady-state frequency is below 59.5 Hz. Percentages for EEA Level 3 Load shedding will be based on previous year's TDSP peak Loads, as reported to ERCOT, and will be reviewed by ERCOT and modified annually.

EReOT PROTOCOLS - JANUARY 1,2010 5-13 PUBLIC SECTION 5: DISPATCH The objective of the EEA is to provide for maximum possible continuity of service while maintaining the integrity of the ERCOT Transmission Grid in order to reduce the chance of cascading outages. ERCOT's operating procedures shall meet the following goals while continuing to respect the confidentiality of market sensitive data:

(I) Use of the market to the fullest extent practicable without jeopardizing the reliabilty of the ERCOT System;

(2) Use of 

### Responsive Reserve Services and other Ancilary Services to the extent permitted by ERCOT System conditions;
(3) Maximum use ofERCOT System capabilty; 

### (4) Maintenance of station service for nuclear Generation Resource Facilties;

(5) Securing of startp power for Generation Resources;

(6) Operation of power Generation Resources during loss of communication with ERCOT;

(7) Restoration of service to critical Loads in the maer defined in the Operating Guides; and

(8) Restoration of service to all Cusomers following major system distuances, giving 

### priority to the larger grups of Customers. ERCOT shall be responsible for coordinating with QSEs and TDSPs to monitor system conditions, initiating the EEA levels, notifying all QSEs, and coordinating the implementation of 

### the EEA levels while maintaining trmission security limits. ERCOT, at management's discretion, may at any time issue an ERCOT-wide appeal through the public news media for volunta energ conservation. 

### During the EEA, ERCOT has the authority to obtain energy from Direct Curent (DC) Ties or 

### Block Load Trasfers (BLTs) from non-ERCOT Control Areas when capacity is available.

Some of the EEA levels wil not be applicable if 

### transmission security violations exist. There

may be insuffcient time to implement all levels in sequence, but to the extent practicable, 

### ERCOT wil use Ancilar Services which bidders have made available in the maret to maintain or restore reliabilty. 

### ERCOT may immediately implement EEA Level 3 any time the steady-stte system frequency is below 59.8 Hz and wil immediately implement EEA Level 3 any time the steay-state 

### frequency is below 59.5 Hz. 

### Percentages for EEA Level 3 Load shedding wil be based on previous year's TDSP peak Loads, 

### as reported to ERCOT, and wil be reviewed by ERCOT and modifiect anually.

EReOT PROTOCOLS - JANUARY 1,2010 5-13 PUBLICSECTION 5: DISPATCH



### 5.6.6.2 General Procedures Prior to EEA Operations Prior to declaring EEA Levell detailed in Section 5.6.7, EEA Levels, ERCOT shall: (1) Start RMR units available in the time frame of the emergency. RMR units should be loaded to full capability; (2) Issue Dispatch Instructions to QSEs to suspend any ongoing ERCOT required generating unit or Resource performance testing; (3) Utilize available Resources providing 30-Minute Non-Spinning Reserve Services (30MNSRS) that can be deployed to increase Responsive Reserves; and . (4) ERCOT shall use the Reserve Discount Factor (RDF) for the purpose of monitoring Physical Responsive Capability (PRC). The PRC will be used by ERCOT to determine the appropriate Emergency Notification and EEA levels.

5.6.7 EEA Levels EEA Levell - Maintain ERCOT Physical Responsive Capability (PRC) on Resources plus RRS MW provided from LaaR Equal to 2300 MW.
ERCOTwill: (1) Utilize available DC Tie capability that is not already being used by the market; (2) Notify the Southwest Power Pool (SPP) Security Coordinator; and (3) Issue Out of Merit Order (OOM) Dispatch Instructions to uncommitted units available within the expected timeframe of the emergency. (4) Inquire about availability of BLTs. QSEs will: (1) Notify ERCOT of any Resources uncommitted but available in the timeframe of the emergency. (2) Immediately update the HSL of any On-line Resource that is capable of providing extra capacity within thirty (30) minutes. The extra capacity must already be part of the QSE's Up Balancing bid curve in order for SPD to utilize the updated Resource Plan.

ERCOTPROTOCOLS-JANUARY 1,2010 5-14 PUBLIC SECTION 5: DISPATCH

5.6.6.2 General Proceures Prior to EEA Operations 

### Prior to declaring EEA Levell detailed in Section 5.6.7, EEA Levels, ERCOT shall:

(1) Start RM units available in the time frme of 

### the emergency. RM units should be loaded to full capabilty;

(2) Issue Dispatch Instrctions to QSEs to suspend any ongoing ERCOT required generating unit or Resource performance testing;

(3) Utiize available Resources providing 30-Minute Non-Spinning Reserve Services (30MNSRS) that can be deployed to increase Responsive Reserves; and ' 

### (4) ERCOT shall use the Reserve Discount Factor (RF) for the purose of monitoring Physical Responsive Capabilty (PRC). The PRC wil be used by ERCOT to determine the appropriate Emergency Notification and EEA levels.

5.6.7 EEA Levels 

### EEA Levell - Maintain ERCOT Physical Responsive Capabilty (PRC) on Resources plus RRS MW provided from LaaR Equal to 2300 MW. 

### ERCOTwil:

(1) Utilze available DC Tie capabilty that is not already being used by the market;
(2) Notify the Southwest Power Pool (SPP) Securty Coordinator; and

(3) Issue Out of 

### Merit Order (OOM) Dispatch Instrctions to uncommitted units available within the expected timeframe of the emergency.

(4) Inquire about availabilty of BL Ts.
QSEs wil: 

### (l) Notify ERCOT of any Resources uncommitted but available in the timeframe of the emergency.

(2) Immediately update the HSL of any On-line Resource that is capable of providing extra

capacity within thirt (30) minutes. The ext capacity must already be part of the QSE's Up Balancing bid curve in order for SPD to utilize the updated Resource Plan.

ERCOTPROTOCOLS-JANUARY 1,2010 5-14 PUBLIC

# Attachment 7

ERCOT Protocols Section 6: Ancillary Services 

# Attachment 7



# ERCOT Protocols Section 6: Ancillary Services

## ERCOT Protocols Section 6: Ancillary Services

February 1, 2010

PUBLIC 

# ERCOT Protocols Section 6: Ancillary Services

February 1, 2010

PUBLIC

# Attachment 8

Emergency Operations for ERCOT Chapter 25, Subchapter S 

# Attachment 8



# Emergency Operations for ERCOT 

# Chapter 25, Subchapter SCHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS. Subchapter S. WHOLESALE MARKETS. (5) ERCOT shall make the following available to market participants through market notices and by posting on a publicly accessible section of the ERCOTweb site: §25.507(d)(5) continued (A) Methodology used to develop baseline formulas; (B) Formulas used for wholesale market settlement; and (C) Equations used to determine an ElLS resource's compliance with its obligations in an ElLS deployment. (e) Compliance. QSEs representing ElLS resources are subject to penalties for failure to meet their obligations under this section. ERCOT shall withhold all or part of an ElLS resource's capacity payment for a contract period and suspend participation in ElLS for six months if the ElLS resource fails to make its committed load available during its committed hours, or fails to meet its load reduction obligations in an ElLS deployment event. In order to be reinstated after the suspension the load must demonstrate its capability of performing the service by satisfactorily performing a test conducted by ERCOT. (t) Reporting. Within 10 days of the ElLS awards for a contract period, ERCOT shall report publicly the number of MW procured per time period, the number of resources providing the service. and the projected total cost of the service for that contract period. ERCOT shall review the effectiveness and benefits of the ElLS and report its fmdings to the commission annually within 70 days of the completion of the ElLS program year. The report shall contain, at a minimum, the number of MW procured in each period, the total dollar amount spent, the number and level of EECP events, and the number and duration of deployments. (g) Implementation. EReOT shall develop additional procedures, guides, and/or protocols that are consistent with this section and that ERCOT finds necessary to implement ElLS,' including but not limited to developing a standard form ElLS Agreement and specific performance guidelines and grace periods for ElLS Resources. (h) Self Provision. ERCOT shall maintain procedures for self provision of ElLS by any QSE.

§25.507--3 effective date 11128/07 

### CHAER 25. SUBSTANIVE RULES APPLICABLE TO ELECTRIC SERVICE

PROVIERS. 

### Subchapter S. WHOLESALE MATS. (5) ERCOT shall make the following available to market paricipants through market notices and by

posting on a publicly accessible section of the ERCOTweb site: §25.507(d)(5) continued (A) Methodology used to develop baseline formulas;

(B) Formulas used for wholesae maret settlement; and (C) Equations used to determine an ElLS resource's compliance with its obligations in an ElLS deployment. (e) Compliance. QSEs representing ElLS resoures are subject to penalties for failure to meet their obligations under this section. ERCOT shall withold all or par of an ElLS resource's capacity payment
for a contrt period and suspend paricipation in ElLS for six months if the ElLS resource fails to make its committed load available during its committ hours, or fals to meet its load reduction obligations in an ElLS deployment event. In order to be reinstated afer the suspension the load must demonstrate its capabilty of performing the service by satisfactonly performing a test conducted by ERCOT.

(t) Reporting. Within 10 days of the ElLS awards for a contrct penod, ERCOT shall report publicly the number of MW procured per time period, the number of resources providing the service, and the projected tota cost of the service for that contrct period. ERCOT shall review the effectiveness and benefits of the EILS and report its findings to the commission anually within 70 days of the completion of the ElLS program year. The report shall contain, at a minimum, the number of MW procured in each penod, the tota dollar amount spent, the number and level of EECP events, and the number and duration of deployments. (g) Implementation. EReOT shall develop additional procedures, guides, and/or protocols that are consistent with this section and that ERCOT finds necessary to implement ElLS,' including but not limited to developing a stadad form ElLS Agrement and specific performance guidelines and gre penods for ElLS Resources.

(h) Self Provision. ERCOT shall maintain procdures for self provision of ElLS by any QSE.

§25.507--3 effective date 11/28/07