Technical Issues Related to Retail-Load Provision of Ancillary Services

41 Pages·2003·0.28 MB·English

New England Demand Response Initiative
TECHNICAL ISSUES RELATED TO RETAIL-LOAD PROVISION OF
ANCILLARY SERVICES

Background Issues Discussion
Brendan Kirby and Eric Hirst*
February 10, 2002
1. Introduction
Responsive load is the most underutilized reliability resource available to the power
system. It is currently not used at all to supply spinning reserve.† This background issues
paper discusses the technical requirements for load, or any resource, to provide
contingency reserves to the electric power system. It discusses why some loads may be
ideal providers of contingency reserves; why some loads are better at providing spinning
reserve than they are at providing any other type of response. It examines the existing
reserve resource mix in New England and begins to quantify the benefits to the power
system of encouraging loads to provide spinning reserve. It discusses the differences
between load and generation as spinning reserve resources and ways to accommodate
loads while increasing power system reliability. Examples of available load response
technologies are provided with a discussion of how they could be used for spinning
reserve.

This paper concentrates on spinning reserve, as opposed to all contingency reserves or all
ancillary services for three reasons. First, New England may have a market for spinning
reserve before it has markets for other ancillary services. Second, loads are different than
generators. The tempting approach of incrementally adapting ancillary service
requirements which were established when generators were the only available resources,
will not work. While it is easier for most generators to provide replacement power and
non-spinning reserve (the slower response services) than it is to supply spinning reserve
(the fastest service) the opposite is true for many loads.‡ Similarly, nonperformance risks
and monitoring requirements (and costs) are fundamentally different for loads than they
are for generators. Starting with the slower reserve services and incrementally adjusting
requirements as experience is gained will block the most attractive responsive loads from
ever supplying ancillary services because the loads are not able to sustain the longer
response required for the slower services and prices of the slower reserves are much
lower than those for spinning reserve. We need to find other ways to develop this
resource and build system operator confidence.

* Brendan Kirby is a senior researcher at the Department of Energy’s Oak Ridge National Laboratory in
Oak Ridge, TN. Eric Hirst is a Consultant in Electric-Industry Restructuring in Bellingham, WA.
† Pumped-storage facilities are sometimes used as spinning reserve while in the pumping mode but these
are more like generators than loads. They are large individual facilities with full utility instrumentation and
control. Most importantly, they are primarily in the energy business.
‡ The limited amount of storage available to most loads limits the response duration.
D R A F T 1
Responsive load can be as reliable and robust a resource as generation. However, the way
it achieves that robustness and reliability is through aggregation of numerous independent
loads rather than through the impressed commitment of a few generators. To obtain the
full economic and reliability value of responsive load to the overall power system the
rules that govern contingency reserves need to be addressed.
D R A F T 2
2. Reserve Requirements
The electric power system is unique in that aggregate production and consumption must
be matched instantaneously and continuously. Several types of controllable reserves are
maintained to help the system operator achieve this required generation/load balance.
Regulating reserves compensate for the continuous random minute-to-minute fluctuations
in load and uncontrolled generation. Frequency-responsive reserves compensate for the
frequency deviations. The daily cycling of load is compensated through load following
and generator dispatch. Finally, sudden failures of generation and transmission are
addressed with three additional reserve products: spinning reserve, supplemental reserve,
and replacement reserve (collectively referred to as “contingency reserves”).

Conceptually the generation/load balance can be maintained by controlling generation,
load, or both. Historically, system operators have tended to control generation almost
exclusively. Generators are typically in the business of providing their services to the
power system so their business model (whether they are owned by an integrated utility or
are independent) accommodates following system operator directives. Communications
and control technology also made it easier to monitor and control a few large resources
than numerous smaller resources. Consequently the rules governing how the power
system is operated were developed at a time when large generators were essentially the
only resources available to support system reliability. Rules were prescriptive as to the
actions to be taken and the technologies to be used rather than being results oriented (i.e.,
performance based).

Restructuring has changed the business relationships between generators and the system
operator. Technology has advanced to allow loads to be responsive. Energy costs have
risen and have become more volatile from hour-to-hour, which provide incentives for
loads to respond. Rules established by regulators and technical organizations are being
changed to accommodate this new set of circumstances.

2.1 Technical Requirements
While responsive load can theoretically provide almost any service the power system
requires (black start may be the only exception), most loads are best suited to provide
contingency reserves. Contingency reserves restore the generation/load balance after the
sudden unexpected loss of a major generator or transmission line. Power system
frequency drops suddenly when generation trips, as shown in Figure 1. In these instances,
there is no time for markets to react. In this case frequency sensitive generator governors
responded immediately to stop the frequency drop. Spinning and supplemental reserves
successfully returned frequency to 60 Hz within ten minutes. Power systems typically
keep enough contingency reserves available to compensate for the worst credible event
(contingency). This is typically the loss of the largest generator or the largest importing
transmission facility. In Texas the simultaneous loss of two nuclear plants is credible (as
shown by the event recorded in Figure 1) so the Electric Reliability Council of Texas
requires over 2600 MW of contingency reserves. Frequency response, spinning,
D R A F T 3
supplemental, and replacement reserves operate in a coordinated fashion, as shown in
Figure 2.
60.04
60.02
60.00
z)
H
Y ( 59.98
C
EN 2600-MW
U Generation
EQ 59.96 Lost SPINNING AND
FR SUPPLEMENTAL
RESERVES
59.94
RESPONSE
59.92
GOVERNOR RESPONSE
59.90
5:50 6:00 6:10 6:20 6:30
TIME (pm)
Figure 1 Governor response and contingency reserves successfully restored the
generation/load balance after the loss of 2600 MW of generation.
Contingency Spinning & Replacement Reserve
Occurs Supplemental
Reserve
Frequency
Responsive
Reserve
-10 0 10 20 30 40 50 60
Minutes
Figure 2 Contingency reserves provide a coordinated response to a sudden loss of
supply.
2.2 Regulations and Policies
While the general concepts of system operations and reliability are well established
implementation details continue to evolve as the industry is restructured. The Federal
D R A F T 4
Energy Regulatory Commission (FERC), the North American Electric Reliability
Council (NERC), the Northeast Power Coordinating Council (NPCC), and ISO New
England (ISO-NE) all have rules and procedures that govern contingency reserve
requirements. These rules are not yet consistent among organizations but the trend
towards open, technology neutral market based solutions is clear.
2.2.1 FERC
The Federal Energy Regulatory Commission (FERC 2002a), in its notice on Standard
Market Design (SMD), shows a clear preference for market-based solutions for energy
supply and reliability. They also encourage demand participation on an equal footing
with generation. The proposed SMD specifies day-ahead markets for spinning and
supplemental reserves, but not for the 30-minute replacement reserve. These markets are
to be integrated with the energy market, much as New York does. FERC also proposes
operation of real-time markets for ancillary services, again, much as New York proposes
in its Real-Time Scheduling system.
2.2.2 NERC
In its most recent operating manual (NERC 2002) NERC has continued its move away
from prescriptive requirements for operational practices to relying more on performance
standards. Policy 1 on "Generation Control and Performance" specifies two standards that
control areas must meet to maintain reliability in real time.§ The Control Performance
Standard (CPS) covers normal operations and the Disturbance Control Standard (DCS)
deals with recovery from major generator or transmission outages.

Policy 1 still discusses the resources that control areas will need to meet the performance
standards. Each control area is required to have sufficient operating reserves to “account
for frequency support, errors in load forecasting, generation loss, transmission
unavailability, and regulating requirements”. It defines “sufficient operating reserves” as
“the capacity required to meet the Control Performance Standard (Section A),
Disturbance Control Standard (Section B), and Frequency Response Standard (Section C)
of this Policy”.**

NERC’s DCS is a performance measure; it specifies that the control area must recover
the generation/load balance within 15 minutes of the start of a contingency. To provide
resources to meet the DCS Policy 1 defines contingency reserves as a subset of operating
reserves:

Each CONTROL AREA shall have access to and/or operate CONTINGENCY
RESERVES to respond to DISTURBANCES. This CONTINGENCY RESERVE
is that part of the OPERATING RESERVES that is available, following loss of
resources by the CONTROL AREA, to meet the Disturbance Control Standard
(DCS). CONTINGENCY RESERVE may be supplied from generation,

§ Policy 1 contains five additional standards: Frequency Response and Bias, Time Control, Automatic
Generation Control, Inadvertent Interchange, and Surveys.
** The frequency response standard will likely evolve into a performance standard similar to CPS and DCS
but it is currently still only a specification of how to set the frequency bias.
D R A F T 5
controllable load resources, or coordinated adjustments to INTERCHANGE
SCHEDULES.††

Policy 1 goes on to state that each regional reliability council will establish contingency
reserve policies covering the minimum reserve requirements, the mix of spinning and
supplemental reserves, and “the limitations, if any, upon the amount of interruptible load
that may be included” (emphasis added). There is a further requirement that each control
area or reserve sharing group carry at least enough contingency reserves to cover the
most severe single contingency.

There are two important points here. First, the composition of the reserves is not
specified. NERC no longer requires spinning reserves to come from generation (though
regional councils are not prohibited from setting that requirement).‡‡ Second, contingency
reserves are to be used to meet the DCS standard. That is, they are to respond to
contingencies. If they are used to respond to forecast errors, generation or transmission
maintenance, or other such problems, they are not available to respond to contingencies.
This latter distinction is important to responsive loads because it has a large impact on the
response duration. Oddly, as we will discus in greater detail, responsive loads, unlike
most generators, care about what the response is to be used for.

There are two other issues relevant to NERC policy. First, meeting the CPS requirements
(balancing generation and load under normal conditions on a minute-to-minute basis)
uses the regulation ancillary service. In principle, customer loads could provide the
service as well as generators. Because provision of this service requires a change in
output (or consumption) on a minute-to-minute basis and, therefore, requires special
automatic-control equipment at the generator (or customer facility), it seems unlikely that
many retail loads will be able to or want to provide this service.

Second, frequency response requirements are evolving within NERC policy. Clearly
system frequency is important under both normal and contingency conditions. Frequency
is the most ubiquitously available measurement of system health (it can be observed at
any household 110-volt outlet). The automatic generation control system (AGC) uses
regulating resources to precisely control system frequency under normal conditions.
Generators larger than 10 MW are required to have active governors that respond to
frequency deviations. A frequency control standard similar to CPS and DCS will likely
be included in Policy 1 in the future but it is not there yet.

Some responsive loads have the potential to be excellent providers of frequency
responsive reserve under contingency conditions.§§ As will be discussed later, they can
provider faster and greater response than most generators. The cost of providing that
response can also be quite low if the requirement is designed into the load control system.

†† NERC capitalizes terms in their policies with NERC defined meanings.
‡‡ The “Terms and Definitions” in the NERC Operating Manual have not yet been updated and spinning
reserve is still defined as “unloaded generation that is synchronized and ready to serve additional demand.”
§§ This discussion is of intentional/deliberate frequency control action. Many motor loads and most
synchronous generators also have a natural frequency response that aids in maintaining system stability.
D R A F T 6
However, frequency response is not a function that comes naturally to most loads. While
there are many reasons to control loads remotely, and those remote control systems can
be readily converted to provide spinning reserve, there are no similar reasons for loads to
have frequency response capability built in. Hence there is no pool of frequency
responsive loads immediately available with which to run a major test or to start a
responsive load program. Load equipment designers would have to see a long-term
market for frequency response before they started to design the capability into either the
loads or load control systems. In addition to specifying the response details, designers
would have to see a stable set of requirements before frequency response is built into
equipment designs.***
2.2.3 NPCC
NERC's DCS is a performance measure; it specifies what must be accomplished
(recovery within 15 minutes) without specifying how that goal must be reached. NPCC
has about 6 reportable DCS events per month and only 2 DCS violations in the past 2
years. NPCC requirements are more prescriptive concerning how much reserve is
required and what constitute reserves. The reserve definitions are slightly different as
well. Table 1 provides the NPCC reserve definitions (NPCC 2002a)

Table 1 NPCC Contingency reserve definitions (emphasis added) (quoted from
NPCC 2002a)
Reserve Type Description
Operating The sum of the ten-minute and thirty-minute reserves
Ten-minute The sum of the synchronized and non-synchronized reserve that is
fully available in ten minutes
Thirty-Minute The sum of the synchronized and non-synchronized reserve that can
be fully utilized in thirty minutes, excluding capacity assigned to
ten-minute reserve
Synchronized The unused portion of generating capacity which is synchronized
to the system and ready to pick up load to claimed capacity and
capacity which can be made available by curtailing pumping hydro
units.
Non-Synchronized That portion of operating capacity, which is available for
synchronizing to the network and that capacity which can be made
available by applying load management techniques such as
curtailing interruptible loads or implementing voltage reductions.

NPCC’s current definition of synchronized reserves is technology specific (restricted to
generation with an exception for pumped hydro) rather than being performance based.

*** What the requirements are (respond in 20 cycles vs. 1 second or respond at 59.96 Hz vs. 59.94 Hz, for
example) will likely have little impact on the cost of new equipment, but retrofitting existing equipment to
accommodate changing requirements may be prohibitive. Adding frequency response capability after the
fact will also be more expensive than designing the capability into the equipment in the first place.
D R A F T 7
Other than the requirement that synchronized reserve comes from generation the
performance requirement is identical to non-synchronized reserve.

The amount of reserves each control area is required to maintain is somewhat
performance dependent. Control areas that consistently maintain good DCS performance
can reduce the amount of synchronized ten-minute reserve they carry and substitute non-
synchronized ten-minute reserves. Good performers are required to have 20% of their
ten-minute reserves synchronized while poor performers must have 100% of their ten-
minute reserve synchronized. The NPCC Operating Reserve Criteria (NPCC 2002b)
specifies how much of each type of reserves must be maintained (Table 2).

Table 2 NPCC Contingency reserve requirements
10-minute synchronized 10-minute non- 30-minute
reserve synchronized reserve reserve
Amount 25%-100% of first 75%-0% of first 50% of second
required contingency (depending contingency (depending contingency
on control area on control area
performance) performance)
Acquired by 600-700 MW 600-700 MW 600-1000 MW
ISO-NE
Minimum 60 minutes 60 minutes 60 minutes
sustainable
time
Maximum 90-105 minutes 90-105 minutes 4 hours
restoration
time

The NPCC Operating Reserve Criteria and Glossary of Terms recognize the importance
of maintaining system frequency but they do not impose a frequency response
requirement on contingency reserves. Frequency response is addressed by generators
with AGC providing regulation.†††
2.2.4 ISO New England
ISO New England has a peak demand over 25,000 MW and typically acquires about 600
to 700 MW each of spinning reserve, supplemental reserve, and replacement reserve. The
ISO began acquiring more than 1000 MW of replacement reserves in May 2002. The

††† We are not sure why the trend in NPCC and NERC seems to be towards placing the frequency response
requirement with the resources providing regulation. Individual frequency response occurs only after
frequency has deviated significantly (outside the 0.035Hz governor dead-band). This will only occur as the
result of a serious contingency. It seems more appropriate to tie frequency response to the contingency
reserves. The logic for making frequency response a regulation requirement may be that the resources
providing the regulation service (generators under AGC) are more likely to be capable of governor
response.
D R A F T 8
extra amount is intended to make explicit the ISO's former implicit day-ahead
commitment of resources to meet possible additional reserve requirements. The amounts
vary from hour to hour and from month to month; for example, the total amount of
reserves acquired during January 2002 ranged from 1270 to 2000 MW, with an average
of 1730 MW. The largest single contingency in New England is usually the loss of a
nuclear unit (typically operating at 1100 MW) or the loss of the DC tie to Quebec
(operating at up to 1500 MW). Reserve response and duration time requirements are
probably influenced by the generation resource mix which has few quick-start units and
numerous slow-ramping thermal units.

ISO-NE does allow load to provide spinning reserve:
Ten Minute Spinning Reserve (TMSR) (1) is the Operable Capability of a
Generator that is unloaded, is in excess of the quantity required to serve current
demand, is able to begin immediately to supply energy to serve demand, is fully
available within ten minutes and is able to be sustained for a period equal to the
longer of thirty minutes or published NERC or NPCC requirements; (2) is
capacity and energy supplied to pump storage generators operating in the
pumping mode that can be shut down or whose demand can otherwise be reduced
within ten minutes and remain off line or reduced for the longer of thirty minutes
or published NERC or NPCC requirements; and (3) is capacity and energy
supplied to a Dispatchable Load whose demand can be partially or totally reduced
within ten minutes and remain so reduced for the longer of sixty minutes or
published NERC or NPCC requirements. (ISO-NE 2002)

Unfortunately responsive load seems to have been tacked on as an afterthought. While
there are detailed descriptions of how generator operating limits and ramp rate are to be
handled, how lost opportunities are to be compensated, etc. there is no similar detail
provided for responsive loads. Further, it is not clear why ISO-NE requires responsive
load to maintain spinning reserve response for 60 minutes while it only requires
generators to maintain response for 30 minutes. Allowing loads to participate is an
important first step in making requirements technology neutral but it is only the first step.
The requirements need to be based on genuine power system requirements not simply on
the capabilities of the historic supplier. That is not to say that the capabilities and
limitations of resources should not be considered. They should. The system operator’s
objective should be to maximize the benefits to all system users by drawing in as many
resources as possible. Service requirements should accommodate and take advantage of
as many diverse resources as possible.
D R A F T 9
3. Responsive Load as a Spinning Reserve Provider
Spinning reserve has traditionally been supplied from generators. It can be thought of as
providing insurance. You get paid for having it available whether or not it is called upon
to address a system emergency. It should be called upon only in the event of a genuine
system emergency such as a lost transmission line or failed generator. Also, it should be
called upon infrequently, perhaps a few times per month. It should be restored to service
rapidly (within 30 to 60 minutes) so that the power system is protected against the next
contingency. Having the option to use load to supply spinning reserve would provide
another source of revenue for responsive loads, increase the reliability of the electricity
supply by increasing reserves, and decrease all customers energy bills because reserve
generation would be freed up to supply energy.

The basic idea of providing spinning reserve (or any contingency reserve) from load is
quite simple (Kirby and Kueck 2000):
• Rapidly curtail load in response to a DCS event
• Maintain the curtailment until the next category of reserves (non-spinning
followed by 30 minute supplemental) are deployed
• Restore the reserve (and load) to service as rapidly thereafter as possible to be
ready for the next contingency

This requires loads with both storage and control capability, a communications system
that tells the loads when to respond, and monitoring to assure that the load response was
obtained. It also requires a system of rules and tariffs that encourage and accommodate
load response. It is important to bear in mind that only a small percentage of loads need
respond. ISO NE only requires spinning reserve equal to about 4% of total load.

It is critical to evaluate the integrated cost of load response to the load providing the
response. Costs will vary from time-to-time depending on the activities the load is
engaged in. Most loads must maintain control over their own operations, responding to
electricity and ancillary service prices as appropriate at that time.
3.1 Desirable Characteristics
Many different types of loads can potentially supply contingency reserves to the power
system. Good candidates share common characteristics:
3.1.1 Storage
Any load that inherently has some storage in its process, or any process to which storage
can be readily added, is a good candidate to supply contingency reserves. This will not be
direct storage of electricity – 60 Hz power can not be stored directly. The storage will
typically be in the form of the productive effort in which the load is normally engaged.
Candidates include thermal storage (building heating/cooling, water heating, refrigeration
and freezing, etc.), process inventory, compressed air, water pumping, and probably
dozens of other such uses.

D R A F T 10