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 1
In 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 NOxreductions 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 2
If 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 CO2 benefits 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 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 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 NO x 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

3 This 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 4
a 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.

4 We 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 along

with other supply-side resources and are dispatched based on their bids, just like supplyside resources. Importantly, the economic DR programs under development today are

different 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 customers

may 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 NEDRI

participants. 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 \

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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 along

with 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 customers

may begin to use combustion tubines for peak shaving and other purses over the longterm 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

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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

6 In 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.

7 A 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 9
time 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

8 Quick-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 10





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.

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 70 percent of the energy displaced by DR resources would have

come from gas-fired CTs, 10 percent 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 60 percent 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 22
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 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.

IS The 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.

16 This 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 24
PROSYM 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 CO2 based 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

Emergencies
Standard 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 of13
Standard 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 to

initiate 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 13
Standard 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 if it 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 of13
Standard 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 R9.4

2.4.4 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 decisionmag 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

Page40f13
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 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 of Trustees: 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 50f13
Standard 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

Page60f13

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 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 of13
Standard 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 of13
Standard 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 if the 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 100f13
Standard 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? H no, 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 of13
Standard 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 of13
Standard 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

Program
PJM 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, 2003
PJM 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).
P1M Interconnection, 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).
PlM Interconnection, 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 for 2417 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 PlM Interconnection, 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).
PlM Interconnection, 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 11 61,238 (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 Response

Program 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 Response

Program web site or emaiL. Fies 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: 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, 2006
PlM Interconnection, L.L.C.

FERC Electric Tariff

Sixth Revised Volume No.1

Superseding Fourth Revised Sheet No. 421 ..

Fifth Revised Sheet No. 421 »mM 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, 2009
PJM 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. 44
PlM 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

PUBLIC
SECTION 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

ERCOT PROTOCOLS -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

PUBLIC
SECTION 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

PUBLIC
SECTION 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

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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;

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(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.

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(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

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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.

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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.

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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.

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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.

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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.

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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.

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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 S


CHAPTER 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