Synapse Energy Eco nomics, Inc. 1MW BUG Sample Revenue Memo Page 1 of 14



# 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 dema nd 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 ma rk ets to a 1 M W 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 capa city markets with three
ye ar 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. 

## Back **up Generator Revenue A nal**  **ys is**  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. W e assume that she diligently ma intains 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 respons e 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. Wefocus primarily on capacity market revenue 1 , because that is the large majority of pot ential 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.Synapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 2 of 14

pay me nts for energy, which are made when a unit prod uces power, capacity pay me nts are made for the promise to run when needed. In New England, capacity pay me nts are largely the only opportunity for the BUG to earn revenue from demand response because of state air permit regulations. In the mid
-Atlantic reg ion, PJM staff have reported the amount of revenue paid to all dem and response resources (including on
- site generation) in slide 5 of its 2010 Demand Side Response Activity Report:

Figure 1 . PJM Demand Side Response Estimated R evenue. 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 com bination 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 mu ch participation is from load reductions and how much is from BUGs. 

## ISO **- NE Example**  **- Hartford, CT**  Wi th a resource in ISO
- NE’s Forward Capacity Market (FC M), 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 Ti meEm ergency Generation (RTEG) is only called by the ISO
- NE in near
- blackout situations,Synapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 3 of 14

coincident with reducing voltage on the s ys tem 2 . There have been no FCM RTEG dispatch events i n the past three summers. Her annual revenues from the FCM are:

Table 1

. FCM RTEG Capacity Revenues for an I llustrative 1M W U nit, R ecent and N ear F uture 3



### Year **FCM Revenue Year**  **FCM Revenue** 2008 $ 4 1 , 5 00 2011 $ 31,762 2009 $ 4 7,4 50 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 pay me nt 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 aucti on 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

- mo nth, 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 require d 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 Maryl and 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 M W 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 fo rward 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 ye ars. Baltimore is in such a region, called Southwest Mid
-Atlantic Area Council (SW MAAC).

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 CouncilSynapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 4 of 14 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 d uring 2010



### Year **Event History Regions Dispatched**  **MWh BUG**  **?** 2010 Wed s. , May 26, 6pm

- 8pm Washington, D.C. 32 Yes 2010 Fri

. , June 11, 4pm
– 8pm Washington, D.C. 400 Yes
2010 We ds. , July 7, 2pm

– 7pm AECO, BGE, DOM, DPL, JCPL, PECO, PEPCO, PSEG 10,880 Yes

2010 Wed s. , 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.Synapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 5 of 14

Weassume 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 1M W Unit, Recent and Near Future 5



### 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 RPM 6 . These changes will keep the current requirement to be able to run up to 60 hours per summer (June

– Sept, maxim um 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 ev ents, maxim um 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 wil l 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 dem and 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 ma rk et. Energy market prices are expressed in $/MW h. W hile New Englan d 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 ma rk et price that subtracts the amount that the end use customer pays for generation service from the pay me nt price. PJM paid full energy market price to DR during certain hours back in 2005
- 2007,

5 RPM revenues for each calendar year are calcul ated 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).Synapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 6 of 14

and Demand Response energy pay me nts 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 ma rk et in which backup generators participate is the cap acity ma rk et. 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 f rom 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, back up 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 l ocated in W ashington, D.C. would have been dispatched for capacity 30 hours in the summer of 2010. W e do not have data to determine if any backup generation units in PJM chose to run in response to high energy market prices.Synapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 7 of 14



# Ap **pendix A.**  **Cap acity** **Market Rev enue Calculations**  This appendi x 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 followin g 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 ma rk et clearing price for different regions (if applicable), and how one would calculate the calendar ye ar annual capacity market revenue for an example 1 M W backup generation unit. 

## IS **O New England’s Forward Capacity**  **Market** New England accounts for capacity market pay me nts in units of dollars per kilowatt per month ($/kW

mo nth). For our example 1 M W resource, we should multiply the price times 1,000, and then by the num ber 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 t hrough December), as seen in the table below.

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

### Power **Year Price to RTEG** 

**($/kW**
**- month)**  **Calendar**

**Year Jan**  **- May**  **Revenue Jun**  **- Dec** 

**Revenue Calendar Year** 

**Revenue** 20 07/08 $ 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 $ 2 7,421


## PJM’s Reliability

**Pricing Model** PJM accounts capacity market revenues in dollars per M W per day ($/MW

- day). To calculate the revenue for the calendar ye ar 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 mo st 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 mu ch 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 (amountSynapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 8 of 14

of supply and demand, newly built resources, retirements of aging resources, new transmission lin es, etc.). Table A2. Historic RP M Revenues for a 1 M W Demand Response Resource in Baltimore, M aryland



### Power **Year Price** 

**($/MW**
**- day)**  **Calendar**

**Year Jan**  **- May**  **Revenue Jun**  **- Dec** 

**Revenue Calendar**  **Year**

**Revenue** 2007/08 $ 188.54 2008/09 $ 210.11 200 8 $ 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 RP M Revenues for a 1 M W Demand Response Resource in Charlottesville , Virginia



### Power **Year Price** 

**($/MW**
**- day)**  **Calendar**

**Year Jan**  **- May** 

**Revenue Jun**  **- Dec** 

**Re venue**  **Calendar Year**

**Revenue** 2007/08 $ 40.80 2008/09 $ 1 11.92 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 20 11 $ 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 $ 8,420Synapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 9 o f 14



# Ap **pendix B. Demand Response Program Summar** **y** Each of the four RTOs that we researched has a numb er 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 dem and response programs available in each region, with key information about ea ch. 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 ty pe matching the wholesale markets applicable to that program: energy, capacity, reserves, regul ation, etc. W e 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 pai d 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 en d
- use customer’s retail rate. In others, the pay me nt is more complicated and we have tried to explain the scheme or calculation briefly. An y single demand response project (including load reductions and/or backup generat ion) is usually permitted to operat e 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 Capaci ty 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 am ount of participation, an d these details change over time. For example, in 2008 PJM changed the com pensation level in the Economic Lo ad Response P rogram from LMP to LMP minus the end
- use customer’s retail rate. Participation in this program plummeted, as most customers were no l onger 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

.Synapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 10 of 14

Table B1. ISO
- NE Demand Response Programs

**Acrony m**  **Program Name Program**  **Ty pe**  **Notes BUGs Eligible?**  **Annual Max or Min Run Hours Price Paid**  **ISO-NE**
**DALRP Day-A** **head 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 m onthly threshold price which varies with price of natrual gas.

**RTPR Real Time Price** 

**Response Program Energy**  Paid greater of LMP or $100/MW h when window is open. No. State air permits. n/a LMP with floor of $100/MW h

**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

.Synapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 11 of 14

Table B2. MISO Demand Respo nse Programs 9

**Acrony m**  **Program Name Program**  **Ty pe**  **Notes BUGs Eligible?**  **An nual 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 Day
Ahead Financial Schedules for all Demand Response Resource – Ty pe 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-W ide Operating Reserve Constraint Shadow Price + Market-W ide 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 = MarketW ide 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 – Ty pe II Offers cleared in the DayAhead Energy and Operating Reserve Market

9 Reserve resources are fast
- s tart resources that can supply energy (or reduce load) to cover for an un ex pected outage on the system. Regulation resources ramp up and down quickly to balance frequent but small changes in load on the system.Synapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 12 of 14

Table B2 Continued

. MISO Demand Response Programs
**Acrony m**  **Program Name Program**  **Ty pe**  **Notes BUGs Eligible?**  **An nual 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-W ide Operating Reserve Constraint Shadow Price + Market-W ide Regulating and Spinning Reserve Constraint Shadow Price + Market-W ide 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-W ide NonDRR1 Operating Reserve Constraint Shadow Price; Supplemental Reserve Price = Mark et-W ide Operating Reserve Constraint Shadow Price + Reserve Zone Operating Reserve Balance Constraint Shadow Price + Market-W ide 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-W ide Operating Reserve Constraint Shadow Price + Market-W ide Regulating and Spinning Reserve Constraint Shadow Price + Market-W ide 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-W ide 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 monthSynapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 13 of 14

Table B3. PJM Demand Response Programs

**Ac rony** **m Program Name**  **Program Ty** **pe 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 ($/MW h) = Resource sy nchronized reserve offer + estimated resource opportunity cost per MW h of capability + energy use per MW h of capability * For DR, estimated resource opportunity cost per MW h of capability = $0 * Energy use per MW h of capability = forecast LMP x Energy use MW / sy nchronized 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 ($/MW h) = 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 ($/MW h) = Resource regulation offer + estimated resource opportunitycost per MW h of capability * For DR, estimated resource opportunity cost per MW h 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. LMPSynapse Energy Economics, Inc. 1MW BUG Sample Revenue Memo Page 14 of 14

Table B 4

. SPP Demand Response Programs

**Acrony m**  **Program Name Program**  **Ty pe**  **Notes BUGs Eligible?**  **An nual 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 approxim ately 1,500 MW participating in the EIS Mark et, producing over 5,000 GW h (including 50 MW h of load reduction) during 2009. Fourteen SPP member utilities administer 36 DR programs, five dynam ic 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 mi nimum load reduction requirements