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Memorandum

To: Stacy Angel, Program Manager

From: Doug Hurley, Associate

Date: June 27, 2011

Re: Sample Revenue for a 1 MW Backup Generation Unit

Background

EPA staff are interested in the recent and near-term future market revenues available to backup

generators in the RTO areas of SPP, MISO, New England, and PJM. Data were not available for SPP 

and MISO, but the other two regions have a history of participation by backup generation in their 

Demand Response programs. The programs set rules for all demand response, whether load is 

reduced due to changes in energy usage or from the use of on-site backup generation. This memo 

focuses on backup generation.

In both ISO-NE and PJM territories, backup generation has been dispatched for capacity no more 

than 30 hours during any of the past three summers. The annual revenue available from RTO 

markets to a 1 MW unit varies from under $10,000/year to over $80,000/year depending upon the 

specific year and the location in which the unit is installed. Based upon capacity markets with threeyear forward auctions, these values are already known through May of 2014. Additional regulatory 

changes in the RTO markets may also affect revenue paid to, and hours of use for, backup 

generation.

Backup Generator Revenue Analysis

Imagine an energy manager for a chain of hospitals. She manages a 1 MW backup generation (BUG) 

unit at locations in Hartford, CT; Baltimore, MD; and Charlottesville VA. We assume that she diligently 

maintains all necessary air permits required to operate the unit, and dutifully responds each time her 

units are dispatched by ISO-NE or PJM. Although she has been approached by demand response 

providers to manage these resources for her, they need a portion of the revenue to operate their 

business. Although participation in the markets requires numerous management and reporting 

activities, we assume that she is performing these duties with her own staff, and keeps the entirety of 

these market revenues. If she were to agree to a contract with a demand response provider, she 

would only keep a portion of the amounts calculated here. The revenue splits are in private contracts, 

and not available to be reported in this memo.

We focus primarily on capacity market revenue1, because that is the large majority of potential 

revenue for BUGs. In general terms, capacity market revenues are paid to the lowest price set of 

resources that are willing and able to generate power or reduce load during peak load hours. Unlike 

 

1

Details on the various wholesale market programs are described in Appendix B.
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payments for energy, which are made when a unit produces power, capacity payments are made for 

the promise to run when needed. In New England, capacity payments are largely the only 

opportunity for the BUG to earn revenue from demand response because of state air permit 

regulations. In the mid-Atlantic region, PJM staff have reported the amount of revenue paid to all 

demand response resources (including on-site generation) in slide 5 of its 2010 Demand Side 

Response Activity Report:

Figure 1. PJM Demand Side Response Estimated Revenue. 

Source: PJM 2010 Demand Side Response Activity Report. Slide 5.

In the most recent years, revenues from PJM’s capacity market are dominant. From 2005 – 2007, a 

combination of favorable market rules and high energy prices produced large revenues from the 

Economic Energy program, but both of those conditions have changed. PJM does not report how 

much participation is from load reductions and how much is from BUGs.

ISO-NE Example - Hartford, CT

With a resource in ISO-NE’s Forward Capacity Market (FCM), she knows both how much she has 

earned as a 1 MW capacity resource during the past three years and how much she will earn up 

through May 2014. The ISO-NE has already completed the forward auctions for this timeframe, and 

the prices are known. There is little risk of her being unable to comply with any dispatches, as Real 

Time Emergency Generation (RTEG) is only called by the ISO-NE in near-blackout situations, 
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coincident with reducing voltage on the system2. There have been no FCM RTEG dispatch events in 

the past three summers. Her annual revenues from the FCM are:

Table 1. FCM RTEG Capacity Revenues for an Illustrative 1MW Unit, Recent and Near Future3

Year FCM Revenue Year FCM Revenue

2008 $ 41,500 2011 $ 31,762

2009 $ 47,450 2012 $ 29,222

2010 $ 40,804 2013 $ 27,421

ISO-NE Regulatory Future

The next two Forward Capacity Auctions will auction capacity for delivery in June 2014 and June 

2015. Both auctions will have an administrative floor price, expected to grow about 5% each year. 

Although her payment rate depends upon many factors, she can reasonably expect FCM revenues to 

be stable for 2014 and 2015. However, the FCM will most likely no longer have an administrative floor 

price starting with the capacity auction for delivery in June 2016, and the New England market is 

currently oversupplied with capacity. The price will likely drop significantly, at least for a few years 

thereafter, to levels that approach only $1/kW-month, based upon historical capacity prices and other 

indicators. This price is roughly one third of the price from the auction for June 2013. However, this 

outcome is very dependent upon numerous factors, including final changes in market rules and the 

potential retirements of existing generation.

The FCM rules have no specific limit on the number of hours that a RTEG resource may be called, 

and this will not change in the near future. Realistically, RTEG units are only allowed to be 

dispatched during near blackout situations. The ISO is required to plan the system to avoid these 

conditions, so the actual risk of running in more than a few hours in any year is very low.

PJM Examples - Baltimore, MD and Charlottesville, VA

Her Maryland and Virginia units are enrolled in PJM’s capacity market, the Reliability Pricing Model 

(RPM). Much like in New England, she knows not just how much she has earned as a 1 MW 

capacity resource during the past three years, but also how much she will earn up through the end of 

May 2014. PJM has already completed the forward auctions for this timeframe, and the prices are 

known. PJM, however, is slightly more complicated because the price is very different depending 

upon the location of the unit. In the less populated western regions of the PJM territory (simply called 

“RTO” or “Non-MAAC”4), transmission constraints are not a factor, and capacity prices are generally 

lower in most years. Her unit in Charlottesville, VA is in this region. In the more congested eastern 

regions, prices are often much higher, at least in some years. Baltimore is in such a region, called 

Southwest Mid-Atlantic Area Council (SWMAAC). 

 

2

Backup generation in PJM is called along with all other demand response resources.

3

FCM revenues for each calendar year are calculated as shown in Appendix A.

4 MAAC stands for Mid-Atlantic Area Council
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Figure 2. PJM Locational Deliverability Areas

Although there have been relatively few dispatches in the past few summers, the long hot summer of 

2010 was an exception, with six different events. Her units were only called to run on three days, for 

at total of 5 hours in Charlottesville and 19 hours in Baltimore.

 Table 2. Demand Response Capacity Events in PJM during 2010

Year Event History Regions Dispatched MWh BUG?

2010 Weds., May 26, 6pm - 8pm Washington, D.C. 32 Yes

2010 Fri., June 11, 4pm – 8pm Washington, D.C. 400 Yes

2010 Weds., July 7, 2pm – 7pm AECO, BGE, DOM, DPL, JCPL, PECO, 

PEPCO, PSEG

10,880 Yes

2010 Weds., August 11, 2pm – 7pm Washington, D.C. 210 Yes

2010 Thurs., September 23, 11am – 8pm BGE and VA, WV, MD portions of APS 6,400 Yes

2010 Fri., September 24, 1pm – 6pm BGE and VA, WV, MD portions of APS 3,830 Yes

 Source: PJM Load Management Performance Report 2010-2011. Figures 5 and 6.
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We assume that her units performed during all of these events, and did not suffer any financial 

penalties for non-performance. Her annual RPM revenues per unit at both locations are: 

Table 3. RPM Capacity Revenues for an Illustrative 1MW Unit, Recent and Near Future5

Year Baltimore Charlottesville

2008 $ 73,433 $ 30,112

2009 $ 82,515 $ 38,814

2010 $ 73,135 $ 52,760

2011 $ 49,858 $ 49,858

2012 $ 45,151 $ 20,132

2013 $ 68,535 $ 8,420

PJM Regulatory Future

The FERC has recently accepted PJM’s proposed changes to demand response in RPM6. These 

changes will keep the current requirement to be able to run up to 60 hours per summer (June – Sept, 

maximum of 10 events, maximum of 6 hours each) as one option, but adds options for both Extended 

Summer Demand Response (May – Oct, no maximum number of events, but with a maximum of 10 

hours for each event) and Annual Demand Response (all year, no maximum number of events, 

maximum of 10 hours each). These rules with new maximum runtime options will not take effect until 

the delivery year beginning June 2014, but that auction will be held in May of this year (2011). It is 

hard to tell how many resources of each type will participate in the auction, but if she is only willing to 

continue with the 60-hour product, it is possible she will be paid a lower price than other RPM 

capacity resources that are willing to be called upon in more hours. She will need to decide if she can 

agree to respond in more than 60 hours, if it is unlikely she’ll be called to react in that many, or if it is 

wiser to remain a 60-hour resource, and risk a lower price.

Demand Response in the Energy Markets

FERC Order 745, issued April 13, 2011, directs each RTO to create market rules that would allow 

demand response resources to be paid the full market price for load curtailments offered into the 

energy markets. This market rule allows demand response to provide voluntary peak shaving 

services to the grid. The energy market pays market participants for power produced – or load 

reduced – during certain hours in response to a price, rather than a reliability event like the capacity 

market. Energy market prices are expressed in $/MWh. While New England already has a Day 

Ahead Load Response Program that pays the full energy market price, BUGs do not participate in 

this program because their state air permits prevent it.7 Currently, PJM pays a much lower energy 

market price that subtracts the amount that the end use customer pays for generation service from 

the payment price. PJM paid full energy market price to DR during certain hours back in 2005-2007, 

 

5

RPM revenues for each calendar year are calculated as shown in Appendix A.

6

134 FERC ¶61,066 Order dated January 31, 2011 in Docket ER11-288-000

7

In New England, nearly 80% of all RTEG resources are located in Connecticut and Massachusetts. Air permits in 

these states restrict usage of backup generators to those hours in which ISO reduces voltage on the system (as an 

emergency precaution to prevent blackouts).
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and Demand Response energy payments were a much larger portion of the total wholesale market 

revenues paid to these resources (see the first chart, above).

There is a possibility that BUGs will participate in the energy market if their air permits do not restrict 

such activity, either through maximum run hours or other restrictions. There will certainly be hours 

during each year when some customers would find it economic to run an on-site BUG rather than 

purchase energy from the electric grid during those high-priced hours. At the moment it is uncertain 

what amount of backup generation, if any, would participate in the energy market. This Order has 

only just been issued, and interim market rules are not due to be filed with the FERC until July 22, 

2011.

Conclusions

At present, the primary wholesale market in which backup generators participate is the capacity 

market. In both ISO-NE and PJM territories, backup generation has been dispatched by their RTO 

capacity market no more than 30 hours over the past three summers.8 Based on the reasonable 

example explored in this memo, the annual revenue available from RTO markets varies from under 

$10,000/year to over $80,000/year depending upon the specific year and the location in which the 

unit is installed. These values are already known through May of 2014, and by mid-June the revenues 

will be known through May 2015, once the next capacity market auctions occur in both regions. 

Additional regulatory changes in the RTO markets may also affect revenue paid to, and hours of use 

for, backup generation.

 

8

Backup generators in New England were not dispatched for capacity at all in the past three years. At the other 

extreme, a backup generator located in Washington, D.C. would have been dispatched for capacity 30 hours in the 

summer of 2010. We do not have data to determine if any backup generation units in PJM chose to run in response to 

high energy market prices.
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Appendix A. Capacity Market Revenue Calculations

This appendix provides the detail behind the capacity market revenues provided in this memo. Both 

New England and PJM determine prices paid in their capacity markets on a “power year” basis, 

where each power year runs from June of one year through May of the following year. For example, 

the RPM auction held in May 2008 set prices for capacity in the PJM territory for the time period from 

June 2011 – May 2012. The rules of both capacity markets allow the possibility of different prices in 

different local areas within the RTO territory. The tables below show the power year, the capacity 

market clearing price for different regions (if applicable), and how one would calculate the calendar 

year annual capacity market revenue for an example 1 MW backup generation unit.

ISO New England’s Forward Capacity Market

New England accounts for capacity market payments in units of dollars per kilowatt per month ($/kWmonth). For our example 1 MW resource, we should multiply the price times 1,000, and then by the 

number of months. To calculate the revenue for the calendar year 2008, we must use the price from 

power year 2007/2008 for the first five months of the year (January through May), and then the price 

from the power year 2008/2009 for the last seven months of the year (June through December), as 

seen in the table below.

Table A1. Historic FCM Revenues for a 1 MW Demand Response Resource in Hartford, Connecticut

Power 

Year

Price to RTEG 

($/kW-month) 

Calendar 

Year

Jan - May 

Revenue

Jun - Dec 

Revenue

Calendar Year 

Revenue

2007/08 $ 3.05 

2008/09 $ 3.75 2008 $ 15,250 $ 26,250 $ 41,500 

2009/10 $ 4.10 2009 $ 18,750 $ 28,700 $ 47,450 

2010/11 $ 2.90 2010 $ 20,500 $ 20,304 $ 40,804 

2011/12 $ 2.47 2011 $ 14,503 $ 17,260 $ 31,762 

2012/13 $ 2.41 2012 $ 12,328 $ 16,894 $ 29,222 

2013/14 $ 2.19 2013 $ 12,067 $ 15,354 $ 27,421 

PJM’s Reliability Pricing Model

PJM accounts capacity market revenues in dollars per MW per day ($/MW-day). To calculate the 

revenue for the calendar year 2008, we must use the price from power year 2007/2008 for the first 

151 days of the year (January through May), and then the price from the power year 2008/2009 for 

the last 214 days of the year (June through December), as seen in the tables below. Note that in 

most years the price for units in Baltimore was higher than the price for units in Charlottesville, so we 

have broken this example into two tables. Prices in congested areas like Baltimore, MD are often 

much higher than those in more rural areas like Charlottesville, VA due to the topography of the 

electric transmission system. Prices in any one year vary due to changing market conditions (amount 
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of supply and demand, newly built resources, retirements of aging resources, new transmission lines, 

etc.).

Table A2. Historic RPM Revenues for a 1 MW Demand Response Resource in Baltimore, Maryland

Power 

Year

Price

($/MW-day) 

Calendar 

Year

Jan - May 

Revenue

Jun - Dec 

Revenue

Calendar Year 

Revenue

2007/08 $ 188.54 

2008/09 $ 210.11 2008 $ 28,470 $ 44,964 $ 73,433 

2009/10 $ 237.33 2009 $ 31,727 $ 50,789 $ 82,515 

2010/11 $ 174.29 2010 $ 35,837 $ 37,298 $ 73,135 

2011/12 $ 110.00 2011 $ 26,318 $ 23,540 $ 49,858 

2012/13 $ 133.37 2012 $ 16,610 $ 28,541 $ 45,151 

2013/14 $ 226.15 2013 $ 20,139 $ 48,396 $ 68,535 

Table A3. Historic RPM Revenues for a 1 MW Demand Response Resource in Charlottesville, Virginia 

Power 

Year

Price

($/MW-day) 

Calendar 

Year

Jan - May 

Revenue

Jun - Dec 

Revenue

Calendar Year 

Revenue

2007/08 $ 40.80 

2008/09 $ 111.92 2008 $ 6,161 $ 23,951 $ 30,112 

2009/10 $ 102.40 2009 $ 16,900 $ 21,914 $ 38,814 

2010/11 $ 174.29 2010 $ 15,462 $ 37,298 $ 52,760 

2011/12 $ 110.00 2011 $ 26,318 $ 23,540 $ 49,858 

2012/13 $ 16.46 2012 $ 16,610 $ 3,522 $ 20,132 

2013/14 $ 27.73 2013 $ 2,485 $ 5,934 $ 8,420 
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Appendix B. Demand Response Program Summary

Each of the four RTOs that we researched has a number of programs in which demand response 

providers can participate with either load reduction or backup generation. The four tables below 

provide information on all of the demand response programs available in each region, with key 

information about each. All were initially developed as parallels to the methods by which generation 

resources participate in the markets, and as such are described by a program type matching the 

wholesale markets applicable to that program: energy, capacity, reserves, regulation, etc. We have 

provided brief notes to help explain each service, an indication of whether or not backup generators 

(BUGs) are eligible, any available information regarding maximum or minimum run time requirements, 

threshold prices, and the price paid to the demand response provider (or end use customer) for the 

service. In some cases, the answer can be quite simple: in PJM’s Economic Load Response 

program, the participant is paid the applicable Locational Marginal Price (LMP) for energy minus the 

end-use customer’s retail rate. In others, the payment is more complicated and we have tried to 

explain the scheme or calculation briefly.

Any single demand response project (including load reductions and/or backup generation) is usually 

permitted to operate in multiple programs simultaneously, assuming they can meet the requirements 

of all of them. For example, if they are interested in responding to high energy prices, demand 

response providers in New England can participate not only in the Forward Capacity Market, but also 

in the Day-Ahead Load Response Program, which dispatches demand response according to daily 

energy prices.

Lastly, it is important to note that the details of any particular program will greatly influence the 

amount of participation, and these details change over time. For example, in 2008 PJM changed the 

compensation level in the Economic Load Response Program from LMP to LMP minus the end-use 

customer’s retail rate. Participation in this program plummeted, as most customers were no longer 

able to afford to curtail their load. All of the programs listed seem to be in a state of constant flux, and 

this table represents a snapshot of their status as of May 2011.
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Table B1. ISO-NE Demand Response Programs

Acronym Program Name Program

Type

Notes BUGs Eligible? Annual Max or Min Run Hours Price Paid

ISO-NE

DALRP

Day-Ahead Load 

Response Program for 

RTDRP

Energy Resources paid Day Ahead 

(DA) Energy Price. No. State air permits. n/a

Day Ahead Locational Marginal Price (DA 

LMP). All offers above monthly threshold 

price which varies with price of natrual gas.

RTPR Real Time Price 

Response Program Energy

Paid greater of LMP or 

$100/MWh when window is 

open.

No. State air permits. n/a LMP with floor of $100/MWh

RTDR Real Time Demand 

Response Resource Capacity Began June 2010, with 

FCM. No. State air permits.

Must be available 8,760 hours 

per year. No maximum

number of hours nor events. 

ISO-NE Operable Capacity 

analysis predicts potential for 

each power year.

Forward Capacity Auction (FCA) clearing 

price.

RTEG Real Time Emergency 

Generation Resource Capacity Began June 2010, with 

FCM. Yes.

Must be available 8,760 hours 

per year. No maximum

number of hours nor events. 

ISO-NE Operable Capacity 

analysis predicts potential run 

hours.

FCA clearing price, prorated at 600 MW.
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Table B2. MISO Demand Response Programs9

Acronym Program Name Program

Type

Notes BUGs Eligible? Annual Max or Min Run Hours Price Paid

MISO

EDR Emergency Demand 

Response Energy

Compensation provided only when 

resource is called during an 

emergency

Yes. (MISO uses the term Behind the 

Meter Generation (BTMG) for BUG).

The higher of the applicable real-time LMP for the location 

of the EDR Participant or the EDR Production Costs during 

the period of actual Demand reductions

DRR-I Demand Response 

Resource Type I Energy Supply through physical Load 

interruption

No. pumped storage resources were 

the largest providers of type 1. In 

September 2009 pumped storage 

stopped participating in DRR as such

Day-Ahead LMP at the applicable location, net of DayAhead Financial Schedules for all Demand Response 

Resource – Type I Offers cleared in the DayAhead Energy

and Operating Reserve Market

DRR-I Demand Response 

Resource Type-I Reserve Supply through physical Load 

interruption

No. pumped storage resources were 

the largest providers of type 1. In 

September 2009 pumped storage 

stopped participating in DRR as such

A minimum continuous 

duration of 60 minutes, all 

cleared reserve capacity

Spinning Reserve Price = Market-Wide Operating Reserve 

Constraint Shadow Price + Market-Wide Regulating and 

Spinning Reserve Constraint Shadow Price + Reserve 

Zone Operating Reserve Constraint Shadow Price + 

Reserve Zone Regulating and Spinning Reserve 

Constraint Shadow Price; 

Supplemental Reserve Price = MarketWide Operating 

Reserve Constraint Shadow Price + Reserve Zone 

Operating Reserve Constraint Shadow Price

DRR-II Demand Response 

Resource Type II Energy

Supply through Behind the Meter 

generation (BTMG) and/or 

controllable Load

Yes. (BTMG = BUG).

Day-Ahead LMP at the applicable Commercial Pricing 

Node, net of Day-Ahead Financial Schedules for all 

Demand Response Resource – Type II Offers cleared in 

the DayAhead Energy and Operating Reserve Market

 

9

Reserve resources are fast-start resources that can supply energy (or reduce load) to cover for an unexpected outage on the system. Regulation resources ramp up and 

down quickly to balance frequent but small changes in load on the system.
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Table B2 Continued. MISO Demand Response Programs

Acronym Program Name Program

Type

Notes BUGs Eligible? Annual Max or Min Run Hours Price Paid

MISO

DRR-II Demand Response 

Resource Type-II Reserve

Supply through Behind the Meter 

generation (BTMG) and/or 

controllable Load

Yes. (BTMG = BUG).

A minimum continuous 

duration of 60 minutes, all 

cleared reserve capacity

Spinning Reserve Price = Market-Wide Operating Reserve 

Constraint Shadow Price + Market-Wide Regulating and 

Spinning Reserve Constraint Shadow Price + Market-Wide 

Regulating Reserve Constraint Shadow Price + Reserve 

Zone Operating Reserve Constraint Shadow Price + 

Reserve Zone Regulating and Spinning Reserve 

Constraint Shadow Price + Reserve Zone Regulating 

Reserve Constraint Shadow Price + Market-Wide NonDRR1 Operating Reserve Constraint Shadow Price; 

Supplemental Reserve Price = Market-Wide Operating 

Reserve Constraint Shadow Price + Reserve Zone 

Operating Reserve Balance Constraint Shadow Price + 

Market-Wide Non-DRR1 Operating Reserve Constraint 

Shadow Price

DRR-II Demand Response 

Resource Type-II Regulation

Supply through Behind the Meter 

generation (BTMG) and/or 

controllable Load

Yes. (BTMG = BUG).

Must be capable of supplying 

Regulating Reserve for a 

minimum continuous duration 

of 60 minutes

Market-Wide Operating Reserve Constraint Shadow Price 

+ Market-Wide Regulating and Spinning Reserve 

Constraint Shadow Price + Market-Wide Regulating 

Reserve Constraint Shadow Price + Reserve Zone 

Operating Reserve Constraint Shadow Price + Reserve 

Zone Regulating and Spinning Reserve Constraint 

Shadow Price + Reserve Zone Regulating Reserve 

Constraint Shadow Price + Market-Wide Non-DRR1 

Operating Reserve Constraint Shadow Price

LMR Load Modifying Resource Capacity

Demand Response Resource Type I 

and Demand Response Resource 

Type II are eligible to be a Capacity

Resource. All DRR participating in 

capacity market are called Load 

Modifying Resources; equal to or 

greater than 100 kW; must be 

available to be scheduled with no 

more than 12 Hours advance notice

Yes. (BTMG = BUG). But BTMG 

cannot be netted against the Load 

Serving Entinty's (LSE’s) forecasted 

Demand in the Forecast LSE 

Requirement calculation.

All Demand Resources utilized 

to net against an LSE’s 

forecasted Demand must be 

available for use in the event of 

an Emergency as declared by 

the Transmission Provider; 

Demand Resource must be 

able to maintain the targeted 

level of Demand reduction or 

firm service level for at least 4 

continuous Hours, at least 5 

times during the Summer 

Season

Auction Clearing Price (“ACP”) for the month
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Table B3. PJM Demand Response Programs

Acronym Program Name Program

Type

Notes BUGs 

Eligible? Annual Max or Min Run Hours Price Paid

PJM

Economic Economic Load 

Response Energy

BUG owner responsible for all 

applicable environmental and use 

permits.

Yes. None. LMP - Retail Rate

Economic Economic Load 

Response

Reserve - 10 

min

BUG owner holds all applicable 

environmental and use permits. Yes.

DR resources limited to providing 25% of 

regulation requirement. ("Batch load" DR 

resources [usually consuming energy but 

regularly reduces consumption to 

production prcesses to minimal or 0 MW] 

may only provide 10-20%)

Resource merit order price ($/MWh) = Resource 

synchronized reserve offer + estimated resource 

opportunity cost per MWh of capability + energy use per 

MWh of capability

* For DR, estimated resource opportunity cost per MWh of 

capability = $0

* Energy use per MWh of capability = forecast LMP x 

Energy use MW / synchronized reserve capability

Economic Economic Load 

Response

Reserve - 30 

min

BUG owner holds all applicable 

environmental and use permits. Yes. DR resources limited to providing 25% of regulation requirement.

Resource merit order price ($/MWh) = resource Day-ahead 

Scheduling Reserve offer + resource Day-ahead 

Scheduling Reserve opportunity costs.

* For DR, resource Day-ahead Scheduling Reserve 

opportunity costs = $0

Economic Economic Load 

Response Regulation

BUG owner holds all applicable 

environmental and use permits. 

Minimum size for DR resources: 0.5 

MW

Yes. DR resources limited to providing 25% of 

regulation requirement.

Resource merit order price ($/MWh) = Resource regulation 

offer + estimated resource opportunity cost per MWh of 

capability

* For DR, estimated resource opportunity cost per MWh of 

capability = $0

Emergency 

(Energy Only)

Emergency Load 

Response - Energy Only Energy BUG owner holds all applicable 

environmental and use permits. Yes. None. LMP

Emergency

Full Emergency Load 

Response (Capacity 

Component)

Capacity BUG owner holds all applicable 

environmental and use permits. Yes. 60 Hrs (10 events, 6 hours each) RPM Price

Emergency

Full Emergency Load 

Response (Energy 

Component)

Energy BUG owner holds all applicable 

environmental and use permits. Yes. None. LMP
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Table B4. SPP Demand Response Programs

Acronym Program Name Program

Type

Notes BUGs Eligible? Annual Max or Min Run Hours Price Paid

SPP

VDDR Variable Dispatch 

Demand Response Energy

SPP’s Tariff recognizes controllable load as a 

resource. Controllable load, cogeneration, and 

backup generation has capacity of approximately 

1,500 MW participating in the EIS Market, 

producing over 5,000 GWh (including 50 MWh of 

load reduction) during 2009. Fourteen SPP 

member utilities administer 36 DR programs, five 

dynamic pricing tariffs, and six voluntary customer 

response initiatives. Mostly interruptible load and 

DLC.

Yes. Variable Dispatch Demand 

Resource (VDDR) primarily

consists of Behind the Meter 

generation.

Participation requirements vary by

program. DR programs accounting for 

64% of the total DR resource reported no 

minimum load reduction 

requirements