Document ID: EPA-HQ-OAR-2008-0708-0840
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2012-05-29T04:00Z

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 three-year 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 revenue, 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 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   SEQ Figure \* ARABIC  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, coincident with
reducing voltage on the system. There have been no FCM RTEG dispatch
events in the past three summers. Her annual revenues from the FCM are:

	Table   SEQ Table \* ARABIC  1 . FCM RTEG Capacity Revenues for an
Illustrative 1MW Unit, Recent and Near Future

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”), 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). 

Figure   SEQ Figure \* ARABIC  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   SEQ Table \* ARABIC  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.

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   SEQ Table \* ARABIC  3 . RPM Capacity Revenues for an
Illustrative 1MW Unit, Recent and Near Future

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. 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. 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,
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.  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.

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 ($/kW-month).  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 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 

 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.

Table B1. ISO-NE Demand Response Programs

Table B2. MISO Demand Response Programs

 

Table B3. PJM Demand Response Programs

Table B  SEQ Table \* ARABIC  4 . SPP Demand Response Programs

	

 Details on the various wholesale market programs are described in
Appendix B.

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

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

 MAAC stands for Mid-Atlantic Area Council

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

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

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).

 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.

 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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