Ancillary Services Cost of Service Study Alberta Electric System Operator

Ancillary Services
Cost of Service Study
Prepared for the
Alberta Electric System Operator
by
EnvVision Energy Consulting Ltd.
April, 2004
EnVision Energy Consulting Ltd.
ABSTRACT
This report examines the costs incurred by the Alberta Electric System Operator
(“AESO”) to provide ancillary services to ensure the safe, stable, and reliable operation
of the Alberta Interconnected Electric System. A review of the match between the
AESO’s costs and the revenues derived from its tariff is presented, as is an analysis of
the factors that drive ancillary service requirements. The report concludes that the
current rate structure can lead to mismatches between costs and revenues (and
potentially to cost shifts among customers), and that there may be more appropriate
billing determinants for certain services than those currently in use. The report
recommends that alternative rate designs, which may provide a better match between
costs and revenues while maintaining other import attributes of a sound rate design, be
considered for certain ancillary services.
GOVERNMENT POLICY
This report has been prepared based on the assumption that the Alberta Department of
Energy will enact a regulation that precludes the allocation of ancillary service costs to
supply customers. Nothing in this report should be construed as either supporting or
not supporting such a regulation. The proposed policy has simply been used as an input
to the recommendations made herein.
DISCLAIMER
This report was prepared for the Alberta Electric System Operator by EnVision Energy
Consulting Ltd. The opinions expressed in this report are those of its author, and not
necessarily those of the Alberta Electric System Operator or any of its employees, agents,
or other contractors.
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1 INTRODUCTION
1.1. The Need for Ancillary Services
The stable operation of an electric transmission system depends on maintaining a
balance between power injections and power withdrawals. The injections include local
generation and imports, while the withdrawals include local load, exports, and losses.
All of these quantities change through time due to routine changes in customers’ energy
requirements, generator production decisions, line switching, and import/export
schedules. They also change—much more suddenly—in response to events like the
failure of a generating unit or a fault on a transmission line. The absence of automatic
responses from protection and control devices or the failure of power system dispatchers
or plant operators to take appropriate actions could result in an imbalance between
injections and withdrawals.1 Such an imbalance can lead to equipment damage, local
outages, or even a system-wide blackout.
Consider, for example, what happens when load increases. The generators on the
interconnected electric system “feel” the increased load and, as a result, they slow
down;2 system frequency and the voltages at load buses start to decline. Governors on
the generators that are providing frequency-responsive reserves will adjust unit power
outputs to arrest the frequency decline and stabilize the system, resulting in a new
operating state in which frequency is slightly below 60 Hz. Once the system is stable,
additional generation can be dispatched to restore the frequency to 60 Hz. To increase
the output of a synchronous generator, more energy input to the prime mover is
required. 3
Arresting any decline in frequency is critical because, while very small deviations from
60 Hz are not serious, larger deviations can be. In thermal plants particularly, auxiliary
devices such as boiler feed pumps and draft fans must operate at or near normal speed
and voltage to function properly. A frequency drop of more than a few hertz may cause
1
Since transmission losses are defined as (generation + imports) – (load + exports), from a theoretical
perspective the injections and withdrawals always balance. When we speak of an imbalance, we really
mean that the operating state in which the injections and withdrawals match is unstable and/or that
voltages and frequency are outside normal operating limits.
2
The slow-down is analogous to what happens if you encounter an up-hill section of road while driving
your car. Unless you push the gas pedal down further, the engine (and the car) begins to slow down.
3
All generators convert some form of mechanical power, normally provided by a steam-, water-, or
engine-driven rotating shaft, into electric power at a given frequency. When the power system
experiences a change in generation or load, the torque on the generator changes and the electric power
output rebalances at a different speed. To restore the speed (which translates directly to system
frequency), the mechanical power input must change. This situation is analogous to what happens
when a car encounters an uphill section of road. If the position of the throttle (i.e., the gas pedal) is not
changed, the car will continue up the hill at a slower speed or, if the hill is steep enough, the engine will
stall. An increase in energy input, accomplished by pushing the gas pedal down farther to increase fuel
flow and engine output, is required to get the car to return to its original (level-road) speed while
climbing the hill.
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loss of the plant auxiliaries and then complete loss of the plant, causing frequency to fall
further. Should the frequency reach 55 Hz, all generation and load would be tripped off
to prevent serious equipment damage.4
Problems are not confined to cases in which system frequency falls. If a block of load is
lost or a tie line carrying exports trips, frequency will begin to rise. The amount of
frequency rise must be limited because it is accompanied by a voltage rise, and elevated
voltages may damage customer equipment. Generators are also susceptible to damage
should the frequency go too high. Here again, the amount of generation must be
adjusted to restore system frequency to 60 Hz.
In spite of the fact that electric power injections and withdrawals are (technically) equal
at all times, we often speak of a shortage or a surplus of generation. A shortage exists
when local generation is inadequate to supply local load, maintain import and export
transactions at their scheduled values,5 and keep system frequency from falling below 60
Hz. Similarly, a generation surplus exists when there is more than enough generation to
supply load and balance import/export schedules, causing system frequency to rise
above 60 Hz.
The important thing to remember is that generation and load must always be balanced
in a controlled manner. This balancing act is performed by a variety of ancillary
services. Some ancillary services are provided by generators equipped to respond
automatically to frequency deviations and/or control signals, while other services are
supplied by generators whose operators are prepared to follow instructions from system
dispatchers. Some ancillary services can be provided by loads.
1.2. Report Outline
The first three sections of the report (including this section) provide background
information. Section 2 describes each of the ancillary services used in Alberta. An
understanding of these services is a prerequisite to a full understanding of how and why
ancillary service costs are incurred and how they should be allocated among
transmission customers. Section 3 provides some background on the past decisions of
the Alberta Energy and Utilities Board (“the Board”). These decisions have established
the tariffs that are currently in place for ancillary services, and they provide guidance as
to what attributes future tariffs should possess.
Sections 4 provides an analysis of the costs of operating reserves. Together with voltage
control costs, they make up approximately 95% of the AESO’s annual ancillary services
budget. This section also includes an analysis of the match between the costs incurred
by the AESO and the recovery of those costs from customers under the current tariff. As
will be seen, revenues and costs do not match particularly well.
4
Obviously, in this state, injections still equal withdrawals; unfortunately they’re both zero.
5
Note that a shortage of local generation can be compensated for (though perhaps only partially) by
increasing import levels; however, operating tie lines at off-schedule values simply shifts the generation
shortage problem to other control areas.
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Sections 5 and 6 of the report examine the appropriate billing quantities for regulating
reserve and contingency reserve, respectively. While the current billing determinant for
both spinning reserve and supplemental reserve—energy consumption—is found to be
appropriate, an alternative to energy consumption is proposed for regulation reserve.
Section 7 contains an examination of the costs of voltage control services and the match
between those costs and the tariff-derived revenues. The analysis concludes that the
existing rate design cannot maintain a close match between costs and revenues. Section
8 examines the cost drivers and appropriate billing determinants for voltage control
services. It is found that the existing billing determinants are reasonable, though certain
adjustments could also be justified.
Section 9 briefly reviews the remaining ancillary services—load shedding, ILRAS, and
black start. Collectively, these services account for less than 5% of the annual cost of
ancillary services. No significant changes to the way in which these costs are allocated is
warranted.
Section 10 provides a summary of the results of the cost-of-service study.
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2 THE ANCILLARY SERVICES USED IN ALBERTA
2.1 Overview
Figure 2.1 presents an overview of the ancillary services used in Alberta. The services
can be categorized into three broad groups: those used in the normal, steady-state
operation of the transmission system; those used to respond to disturbances such as the
sudden loss of a generator, large load, or tie line; and those used following a disturbance
to restore normal operating conditions.
Figure 2.1: The ancillary services used in Alberta.
Ancillary
Services
Normal
Operations
Services
Disturbance
Response
Services
Post-Disturbance
(Recovery)
Services
Regulating
Reserve
Regulating
Reserve
Spinning
Reserve
Load
Following
Spinning
Reserve
Supplemental
Reserve
Voltage
Control
Load
Shedding
Black Start
Brazeau
Fast-Ramp
Interruptible
Load RAS
RAS = “Remedial Action Scheme”
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Normal Operations Services include:
• Regulating Reserve (also called regulation), which is used to follow the moment-to-
moment variations in supply and demand in a control area;
•
Load Following, which tracks the larger, hour-to-hour changes in load that typically
occur in the morning and evening hours or that arise in response to changes in the
weather, industrial plant operations, etc.;
•
Voltage Control, which involves the injection of real power, or the injection or
withdrawal of reactive power, to maintain power transfer capabilities and pre- and
post-contingency transmission voltages.
Disturbance Response Services include:
•
Regulating Reserve, which provides increases or decreases in generation in response
to frequency changes caused by the loss of a generator, import, load, or export;
•
Spinning Reserve, which is generation that is on line, loaded to less than its maximum
capability, and available to serve customer demand immediately should a
contingency occur;6
•
Load Shedding, which causes loads to trip when system frequency drops so low that
other disturbance response mechanisms may not be able to arrest its decline;
•
Brazeau Fast-Ramp, which causes a rapid increase in the output of the Brazeau hydro
units when frequency drops below a trigger level;
•
Interruptible Load Remedial Action Scheme (“ILRAS”), which is used to trip load
immediately following a loss of import capability.
Post-Disturbance (Recovery) Services include:
•
Any Spinning Reserve that has not already responded to frequency deviations and
that can be dispatched manually (most spinning reserve falls into this category, since
system response to frequency deviations is relatively small);
•
Supplemental (Non-spinning) Reserve, which may be supplied by off-line
(unsynchronized) generators that can produce real power, or on-line loads that can
be curtailed, within 10 minutes of receiving a directive from the System Controller.
•
Black Start (Power System Restoration), which is a service provided by Alberta
generation units that can go from a shutdown condition to an operating condition
without assistance from the transmission system, or by suppliers from outside
Alberta, that can deliver their energy to the transmission system to restart other
generators.
Each of these services is described in more detail in the following sections.
6
Spinning reserve and regulating reserve together constitute what is known under North American
Electric Reliability Council (“NERC”) policies as frequency-responsive reserve (“FRR”). FRR is unloaded,
spinning generation capacity whose purpose is to arrest frequency decline.
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2.2 Normal Operations Services
2.2.1 Regulating Reserve (Regulation)
Figure 2.2 shows the power delivered to Alberta loads as measured at one-minute
intervals over a 24-hour period. The morning ramp, the relatively flat load during the
middle of the day, the rise to the evening peak, and the ramp back down at the end of
the day are all obvious features of this winter weekday load cycle.
What may not be quite as obvious from Figure 2.2 are the much smaller, shorterduration fluctuations that occur as everything from light bulbs to large industrial motors
are turned on and off in response to consumer needs. These variations are clearly visible
in Figure 2.3, which is an enlarged view of the two-hour period enclosed by the small
box in Figure 2.2. During that two-hour period, the AIES load ranges from a low of
~6960 MW to a high of ~7025 MW. There is a slight downward trend over the first hour,
and a general upward trend over the second hour, as shown by the dashed line. The
load varies roughly 20 MW up and down from the general trend, as shown in Figure 2.4.
Figure 2.2: AIES load during a day in January 2002.
8000
AIES Load [MW]
7500
7000
6500
Area enlarged in next figure
6000
5500
0
2
4
6
8
10
12
14
16
18
20
22
Hour of the Day
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To avoid negatively affecting neighbouring electric systems, it is necessary to adjust
Alberta generation so that
(2.1)
generation + scheduled imports = load + scheduled exports + losses.
Because the rapidly varying component of the load changes too quickly for the System
Controller to follow with energy market dispatches, several Alberta generators assume
responsibility for providing regulating reserve (or regulation) under contract to the AESO.
The power output of regulation-providing generation units increases or decreases in
response to signals provided every four seconds by the System Controller’s Automatic
Generation Control (“AGC”) system. The AGC system calculates the changes in
generation necessary to manage the fast component of the load, thereby maintaining the
supply/demand balance.7
Figure 2.3: AIES load during a two-hour period.
7040
AIES Load [MW]
7020
7000
6980
6960
6940
0
15
30
45
0
15
30
45
Time [Minutes within the Hour]
7
It is neither practical nor necessary to maintain a “perfect” supply/demand balance at all times. There
are, however, statistical limits on the allowed deviations from balance, as will be discussed later.
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Figure 2.4: The difference between the actual load and the general trend.
25
20
AIES Load [MW]
15
10
5
0
-5
-10
-15
-20
-25
0
15
30
45
0
15
30
45
Time [Minutes within the Hour]
2.2.2 Load Following
As described in the previous section, the load on the AIES can be viewed as having two
components, one consisting of relatively small, rapid fluctuations in demand, and the
other consisting of the much slower but larger fluctuations that are related to the time of
day, changes in weather, etc. The AESO procures regulation capability from Alberta
generators to track the fast component. The slow component is, at least in theory,
followed by dispatching the next block of generation in the energy-market merit order.
There are several reasons why next-block dispatches, by themselves, cannot match that
component of the load:
• The System Controller cannot predict the slow component of the AIES load exactly.
• For a variety of reasons (the most obvious being an unplanned outage), generators
may not be able to follow dispatch instructions exactly. Even when instructions are
followed, the response of a generation facility depends on a number of variables,
such as ambient temperature, the heat content of fuels, and so on; consequently,
plant performance is not precisely predictable.
• Many changes may be taking place at the same time. For example, the BC tie may
change from exporting 200 MW to importing 400 MW while a significant block of
hydro generation comes on line. Simultaneously, other units may go in or out of
merit as energy market offers and prices change.
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• The rate of change in AIES demand may exceed the ramp rate of the next unit in the
merit order.
There are at least three ways in which the mismatch between the slow component of
AIES load and actual energy-market generation can be dealt with. The first is to procure
extra regulation capability—amounts in excess of those required to deal solely with the
fast component of AIES load—so that units providing regulation can help the energymarket units keep up with changes in demand. The second option is to dispatch higher
up the energy-market merit order. Such above-merit dispatches do not result in
additional ancillary service costs, though they may affect pool prices. A third option,
which is not available at this time, would be to procure load following as a separate
ancillary service.
An example of how regulating units contribute to load following is provided in
Figure 2.5, which shows the slow component of the system load over an hour. The
difference between the output of the units dispatched in the energy market and the slow
component of the AIES load (the shaded area in the figure) is made up by units
providing regulation. What this example shows is that, even if there were no short-term
fluctuations in demand, a certain amount of regulation would still be required to follow
the large-scale changes, i.e., to provide load following service.
Since load following is not a distinct ancillary service, it will not be treated separately in
the balance of this report. The terms “regulating reserve” or “regulation” will therefore
be used to denote the tracking of both the rapid fluctuation in system demand and that
portion of the slower variation not tracked by energy market dispatches.
Figure 2.5: Provision of load following by regulating units.
7100
Base AIES Load [MW]
7000
6900
AIES Load Trend
6800
6700
Output of Energy
Market Units
6600
(Hypothetical)
6500
0
10
20
30
40
50
60
Time [Minutes]
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2.2.3 Voltage Control
Historically, the economics of generation and transmission development in Alberta led
to the creation of a “hub and spoke” transmission system, with a significant fraction of
the province’s generation at the hub in the Lake Wabamun area, and large blocks of load
at the ends of the spokes that run generally to the northwest, northeast, and south of the
generation hub. This network configuration creates several circumstances in which
injections of real power, or injections or withdrawals of reactive power, are required at
specific locations on the transmission system. Generators that are constrained on to
produce real power are providing transmission must-run (“TMR”) service.
2.2.3.1 Real Power Supply (Transmission Must-Run)
The transmission system in the northwest part of the province consists of long, radial
144 kV and 240 kV lines with limited redundancy. Since the northwest area’s generating
capacity is substantially less than the area load, there is an inflow of energy to the area
under normal circumstances, and some of the 144 kV lines can become heavily loaded.
An outage on a single transmission line or a local generator can cause voltages to drop
below acceptable limits, potentially causing some loss of load or, in extreme cases,
voltage collapse. This risk can be partially mitigated by ensuring that area real and
reactive power production is above certain minimum levels. Generators that are
required to run even though they are out of the energy-market merit order are
supplying the Transmission Must-Run (“TMR”) ancillary service.
In addition to protecting against unplanned outages on transmission lines or local
generators, a need for TMR may also arise in various locations from planned or
unplanned maintenance on transmission facilities. The requirements are established on
a case-by-case basis.
Another circumstance that calls for the injection of real power at certain locations on the
transmission system arises in the southern part of the province. Power transfers on the
north-to-south transmission path between Edmonton and Calgary occasionally reach the
capacity of the transmission system. During such operating conditions, voltages in
southern Alberta become difficult to manage. Generation in that region unloads the
north-south path and provides voltage support, thereby reducing the risk of voltage
instability.8
2.2.3.2 Reactive Power Supply
Depending on operating conditions, transmission lines can either produce or consume
reactive power. Power transformers are also reactive power consumers. In order to
balance reactive power supply and demand, devices connected to the transmission
8
On page 2 of Decision 2000-47 (ESBI Alberta Ltd. – IBOC Contract Approval, July 12, 2000), it states: “EAL
noted that in Decision 2000-1 the Board directed EAL to employ a combination of Request for Proposals
and Standing Offers to encourage generation to locate in Southern Alberta in response to a growing
possibility of voltage collapse.”
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system must absorb the reactive power produced or supply the reactive power
consumed. Reactive power can be supplied or absorbed by static devices such as
capacitor banks, reactor banks, and static VAr compensators (“SVCs”). The costs
associated with these devices are included in the wires costs of the transmission owners,
and are not treated as distinct ancillary service costs.
Reactive power can also be supplied or absorbed by generators and other dynamic
devices such as synchronous condensers. Of the generation units available in the
northwest part of the province, two of them (Valleyview and Poplar Hill) are capable of
operating in either power generator mode or synchronous condenser mode. In addition,
the AESO previously contracted with TransAlta to provide a hydro motoring service,
under which certain hydro units could be run as reactive power consumers or suppliers;
that service is no longer required.
Reactive power is also important to the control of system voltages, and consequently to
maintaining the power transfer capability of the transmission system. Adjusting certain
inputs to a power generator while keeping the mechanical power input the same
changes the amount of reactive power that the generator supplies or consumes. The
AESO’s generator interconnection standards specify the reactive-power ranges over
which AIES generators must be able to operate. Unless the specific circumstances
warrant special consideration (as was the case with the Poplar Hill facility), generators
receive no payment from the AESO for reactive power dispatches within the bounds
established in the interconnection standards. Note that, in most cases, the reactive
component of a generator’s output is a by-product of maintaining the voltage at the
unit’s interconnection point at the desired value; specific reactive power flows are not
generally specified.
It is worth noting that transmission lines do not transport reactive power very efficiently
from one location to another on the grid.9 Consequently, the requirements to inject or
absorb reactive power are highly location-specific. Even if it is eventually decided that
generators should be paid for their reactive power, it is not likely that an efficient
competitive market for reactive power can be created. Consequently, reactive power
requirements beyond those that may reside in the generator interconnection standards
are likely to continue to be the subject of negotiations between the supplier and the
AESO.
In summary, location-specific supplies of real or reactive power are used to reduce the
loading on certain transmission paths, improve voltage profiles and voltage stability,
and avoid load-shedding or voltage collapse following a generation or transmission
outage.
9
A typical line’s resistance to the flow of reactive power is five to ten times greater than its resistance to
the flow of real power.
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2.2.3.3 IBOC and LBCSO Generation
The AESO has contracts with certain generators that resulted from the Invitation to Bid on
Credits (“IBOC”) and Location Based Credits Standing Offer (“LBC SO”) processes.10 These
processes were initiated by the AESO’s predecessor—and approved by the AEUB—to
provide incentives for generation development in specific regions of the AIES. The
System Controller has the ability to use these generators to provide TMR and/or
reactive power services. Since the IBOC and LBCSO units are normally used for real
power injection, they will be treated as TMR providers for the purposes of this report.
The contracts under which these units operate are discussed later.
2.3 Disturbance Response Services
Following a contingency involving the loss of Alberta generation or imports, there will
be a shortage of generation11 in the province. Tie line flows will move away from their
scheduled values and, if the loss of generation is large enough, system frequency will
begin to fall noticeably below 60 Hz. (The amount of frequency sag will depend on the
proportion of total available generation, including that on interconnected systems, lost.)
It is desirable to restore frequency and tie flows to normal as soon as possible to that
instability or overloads will not occur, inadvertent energy accumulations will not
become excessive, and the effect of the contingency on the interconnected systems will
be minimized. The AESO uses several mechanisms to arrest the frequency decline
following a loss of supply.
2.3.1 Regulating Reserve
In addition to helping to track the moment-to-moment fluctuations in supply and
demand that are part of normal system operations, regulating units also play a role in
responding to system disturbances. In the case of a loss of Alberta generation, the AGC
signal will indicate a need to increase Alberta supply. Generators providing regulation
will begin to increase their outputs in response to this signal and thereby contribute to
halting any decline in frequency and restoring the supply/demand balance. Thus,
regulation-providing units can be counted as part of the control area’s contingency
reserve requirement.
2.3.2 Spinning Reserve
If the loss of supply created by a system contingency is relatively small, the regulating
units may be able to respond sufficiently to manage it. However, for many
contingencies, additional disturbance response resources are required. Spinning
10
Alberta Energy and Utilities Board. Decision 2000-47: ESBI Alberta Ltd. – IBOC Contract Approval (July 12,
2000) and Decision 2001-18: ESBI Alberta Ltd. – Part F: Location Based Credits – Standing Offer (March 2,
2001).
11
As noted above, supply and demand must always balance. When we speak of a shortage of generation,
we mean that there is not enough generation to maintain injection/withdrawal balance and keep system
frequency and voltages within acceptable limits.
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reserves are provided by qualified on-line generators that are loaded at less than their
maximum outputs. A generator supplying spinning reserve must be under the control
of a governor that detects the frequency decline that accompanies a significant loss of
supply and causes the unit’s output to increase.12
2.3.3 Load Shedding
If a contingency on the transmission system causes frequency to decline, and if that
decline cannot be arrested through other actions (such as the response of regulating
reserve units, spinning reserve units, and changes in tie-line flows), load is tripped off
automatically by frequency-sensitive relays. These underfrequency relays are set such
that, as frequency falls, more and more load is tripped off. A coordinated automatic
underfrequency load shedding (“UFLS”) program is required to minimize the risk of
total system collapse, protect generating equipment and transmission facilities against
damage, provide for equitable interruption of electric supply to customers, and help
ensure the overall reliability of the interconnected systems.
The AESO also has in place an undervoltage load shedding (“UVLS”) scheme in the
Calgary area. The AESO has identified that, under certain system contingencies,
reactive power deficiencies in the Calgary area could lead to a voltage collapse. Under
this scheme, a block of Calgary-area load will be shed if the voltages at several
monitoring points remain below 131 kV for 4 seconds, and another block will be shed if
voltages remain below that level for 15 seconds.
2.3.4 Brazeau Fast-Ramp
The AESO has contracted with TransAlta Utilities to provide a “fast-ramp” service from
the Brazeau hydro units. Hydro units can typically ramp much faster than thermal
units. Assuming one or more of the Brazeau units are not at full output at the time of a
contingency, their outputs can be ramped up very quickly to help arrest the frequency
decline. The fast-ramp service is triggered when frequency falls to 59.5 Hz. The service
is stopped once frequency has recovered to 59.9 Hz to avoid overshoot.
2.3.5 Interruptible Load Remedial Action Scheme (“ILRAS”)
ILRAS is an ancillary service that the AESO procures to enable increased import
capability through the Alberta-BC interconnection. Under the scheme, a certain amount
of load is “armed” when the import level on the interconnection goes above a threshold
level. Should the interconnection trip off when imports are above that threshold, the
load is immediately tripped off. Any loss of imports below the threshold level is
managed by the other disturbance response and recovery services (spinning reserve,
supplemental reserve, etc.). In the absence of ILRAS, Alberta would be required to carry
additional volumes of those other services.
12
The technical requirements for the provision of ancillary services are provided on the AESO’s website at
http://www.aeso.ca/market/5135.html.
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2.4 Post-Disturbance (Recovery) Services
2.4.1 Spinning Reserve
As noted above, the governors on generators providing spinning reserve cause the units’
real power outputs to increase in response to falling frequency. Following that initial
response, the System Controller will issue Ancillary Service Directives to spinning
reserve providers to increase production by up to the total volume of spinning reserve
sold to the AESO. The plants have 10 minutes to reach the directed power output levels.
2.4.2 Supplemental Reserve
Like spinning reserves, supplemental (non-spinning) reserves are also designed to
restore the supply/demand balance following a contingency. They differ from spinning
reserves in that there is no requirement that they be responsive to frequency deviations.
Thus, generators supplying supplemental reserve can be either on-line or off-line,
provided they can deliver their reserve volumes within 10 minutes of an Ancillary
Service Directive. Supplemental reserve can also be provided by interruptible load.
2.4.3 Black Start
In the unlikely event of a full or partial collapse of the AIES, most generation facilities in
Alberta will require external start-up power. This external power is needed for the
many large motors usually present at generating stations; some of the larger stations can
draw up to 10 MW for several hours before its units are capable of synchronizing to the
grid. Therefore, generators that are capable of starting without assistance from the AIES
are needed. Facilities from outside Alberta are also capable of providing blackstart
services.
Blackstart resources should be geographically dispersed, and they must have sufficient
real and reactive power capability to both restart other generators and supply the
charging currents that flow immediately after de-energized transmission lines are
connected to the unit. For security reasons, the details of blackstart services are not
made public.
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2.4.4 A Sample Contingency Response
Figure 2.6 provides an example of the use of both disturbance response and disturbance
recovery services. Approximately 10 minutes into the hour, an Alberta generator
tripped off, resulting in a sudden decrease in total Alberta generation. Immediately
following the contingency, the flow on the BC tie increased to make up for the
generation shortfall. The AGC system detected that the BC tie’s power flow was off
schedule and therefore sent signals to the units under its control to increase their output.
In addition, the governors on the units providing spinning reserve detected the
frequency decline that accompanied the disturbance and signalled for the output of the
spinning reserve units to increase. The increase in the output of the AGC and spinning
reserve units shows up as an increase in total Alberta generation and as a decrease in
available operating reserves.
Following the immediate, automatic response just described, additional spinning
reserves and (possibly) supplemental reserves were dispatched by the System
Controller. Within roughly 10 minutes of the generator trip, sufficient Alberta
generation had been brought online to restore the tie’s flow to its pre-contingency value.
By the end of the hour the System Controller had dispatched sufficient generation from
the energy market to replace the energy supplied by the reserve-providing units,
allowing reserve levels to return to their required levels.
2.4.5 A Note on Reserve Sharing
NERC and WECC rules allow control areas to share reserves. Under written agreement,
the operating reserve requirements of two or more control areas may be combined or
shared if the combination, considered as a single control area, meets the minimum
operating reserve criteria. Similarly, arrangements may be made under which one
control area supplies a portion of another’s operating reserve if such capacity can be
made available such that both control areas meet the minimum operating reserve
criteria. A firm transmission path must be available and reserved for the transmission of
these operating reserves from the supplying control area to the receiving control area.
Alberta has a reserve sharing agreement with the other members of the North West
Power Pool. Under that agreement, any member utility suffering a contingency can call
on its neighbours’ reserves in response. While Alberta incurs a cost to supply its portion
of shared reserves, it is also a beneficiary of the reserve sharing arrangement.
The Ancillary Services Used in Alberta
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Megawatts
Figure 2.6: The response to a loss of Alberta generation.
Operating Reserves
BC Tie Line
Alberta Generation
0
10
20
30
40
50
60
Time [Minutes]
2.5 Ancillary Service Costs for 2002 and 2003
Figure 2.7 shows the AESO’s month ancillary services costs for 2002 and 2003 by service
type. (The “Other” category includes ILRAS, blackstart, Brazeau fast-ramp, and
supplemental governor response.13) Figure 2.8 shows the proportion of the annual costs
accounted for by each service. These charts show that, over the past two years, the
AESO has spent between $10 million and $25 million per month for ancillary services.
The charts also show that the vast majority of the AESO’s ancillary service costs are
13
Hydro generators equipped for the provision of regulating reserves have additional equipment or
control tuning that permits these generators to respond in excess of normal requirements to frequency
deviations caused by system disturbances. However, with changes to the ancillary services market and
the technical specifications for regulating reserve, this service is no longer procured by the AESO.
The Ancillary Services Used in Alberta
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accounted for by (in order) spinning reserve, regulation and load following, voltage
control, and supplemental reserve.
Figure 2.7: Monthly ancillary services costs in 2002 and 2003.
Ancillary Service Costs [M$]
30
25
20
15
10
5
0
1
2
3
4
5
6
7
8
9
10
11
12
Month (2002)
Spin. Res.
Reg & LF
Voltage Ctrl
Supp Res
Load Shedding
Other
Ancillary Service Costs [M$]
30
25
20
15
10
5
0
1
2
3
4
5
6
7
8
9
10
11
12
Month (2003)
Spin. Res.
Reg & LF
Voltage Ctrl
The Ancillary Services Used in Alberta
Supp Res
Load Shedding
Other
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Figure 2.8: Ancillary service cost percentages for 2002 and 2003.
Load Shedding
3%
Other
1%
Supplemental
Reserve
12%
Spinning Reserve
33%
Voltage Control
22%
2002
Load Shedding
3%
Supplemental
Reserve
6%
Regulation &
Load Following
29%
Other
1%
Spinning Reserve
32%
Voltage Control
30%
2003
The Ancillary Services Used in Alberta
Regulation &
Load Following
28%
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3 REGULATORY HISTORY
In this section of the report, the regulatory history of ancillary services cost allocation
issues is reviewed. The purpose is to provide some context for the cost allocation study
and to create a list of the issues that must be addressed in tariff design.
3.1 Decision U97065: 1996 Transmission Tariff
The appropriate allocation of ancillary services costs in Alberta’s deregulated electricity
industry has been considered by the Alberta Energy and Utilities Board (“the Board”) on
a number of occasions. The first instance was in Decision U97065,14 which was the first
decision issued by the Board with respect to transmission tariffs applicable after the
January 1, 1996 implementation of the Electric Utilities Act. In that decision, the Board
allocated the cost of all ancillary services to Rate GIS (Grid Interconnection Service),
which applied to distribution utilities on the basis of their non-coincident peak
demands.
Among the issues raised by parties in the proceeding was the appropriate split of wires
costs between those attributable to non-coincident-peak (“NCP”) demand and those
attributable to coincident-peak (“CP”) demand.15 The NCP vs. CP issue also arose in the
context of ancillary services.16 Gridco17 proposed to allocate 100% of its ancillary
services revenue requirement on the basis of NCP, and therefore through demand
charges. Some parties challenged this allocation, arguing that such costs should be
recovered through a rate charged on the basis of on-peak energy,18 which may be
viewed as a proxy for CP demand.19 One of the interveners recommended a review of
the allocation of ancillary services in conjunction with an analysis of the local/bulk (i.e.,
NCP/CP) allocation ratio of transmission wires costs in the expectation that a significant
amount of ancillary services costs would be found to be CP-related.20
The Board decided that wires costs should be allocated 40% to local facilities (NCP) and
60% to the bulk system (CP). The Board considered the assignment of ancillary services
costs to the GIS charge and their recovery on the basis of NCP to be efficient and
equitable to all customers. The Board noted, however, that a market-based approach to
development and delivery of ancillary services in the future might alter the manner in
14
Alberta Energy and Utilities Board. Decision U97065: 1996 Electric Tariff Applications. 1997 October 31.
15
Ibid., Part 5, Section 4(a).
16
Ibid., Part 5, Section 5(a).
17
Gridco, more formally The Grid Company of Alberta, was the province’s first Transmission
Administrator.
18
Ibid., p. 622.
19
The Board considered that the use of on-peak energy to determine an on-peak load factor gave a simple
proxy for coincident demand (p. 628).
20
Ibid., p. 623.
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which the costs for these services are recovered. Accordingly, the Board directed the TA
to address this at the time of its next GTA.21
3.2 Decision 2000-1: EAL 1999/2000 GTA
The first transmission tariff application following Decision U97065 was filed in April
1998 by ESBI Alberta Ltd. (“EAL”), which was to assume the role of Transmission
Administrator beginning June 1st of that year. Given the short time that had elapsed
since Decision U97065 and the focus on the transition from Gridco to EAL, ancillary
services cost allocation was not studied, and the allocation for the rest of 1998 remained
as it was under the Gridco tariff.
EAL filed its 1999/2000 tariff application on 1998 December 31, and filed an update to
that application on 1999 May 25. The Board released its first decision on that
application, Decision 2000-1,22 on 2000 February 2.
Among the major changes proposed in EAL’s application was the allocation of most
transmission costs on a (roughly) 50/50 basis between generation customers and load
customers. Consistent with that allocation, EAL proposed a 50/50 allocation of ancillary
services costs as well. The proposed tariff separated operating reserve charges from the
other ancillary service charges, made the operating reserves charge a function of pool
price, and allocated 60% of operating reserve costs on a capacity basis and 40% on an
energy basis (consistent with the recovery of wire costs). EAL proposed recovering the
energy costs on an on-peak basis. The remaining ancillary service charges were
similarly structured to recover 60% of costs through capacity charges and 40% through
energy charges, though in this case the energy charge was over all hours.23
Some interveners recommended different demand/energy splits, including 40/60 and
0/100. Others suggested that operating reserves should be charged only to loads, except
that if generators cause additional ancillary service costs to be incurred, a generatorspecific reserve charge could be considered for the next GRA. Other comments to the
Board included:
• all voltage control costs should be allocated to load customers;
• the recovery of operating reserves on an NCP basis tends to over-recover costs from
customers with multiple points of delivery;
• the cost of services procured in an hourly market should not be allocated to capacity
charges, particularly ratcheted peak demand;
21
Ibid., p. 625.
22
Alberta Energy and Utilities Board. Decision 2000-1: ESBI Alberta Ltd. 1999/2000 General Rate Application,
Phase 1 and Phase 2. 2000 February 2.
23
EAL’s ancillary service cost allocation proposals and the comments of interveners are set out in Section
14.2 (starting at p. 201) of Decision 2000-1.
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• the relationship between the ancillary service cost and demand at substations is
much more tenuous that the relationship between physical facilities and demand at
substations;
• while reserves are acquired to prevent load emergencies, such emergencies are
largely caused by supply.
Another ancillary service issue addressed in Decision 2000-1 was that of charges to dualuse (a.k.a. “hum-along”) customers. These are customers that have both load and
generation on site and whose energy injections or withdrawals in any 15-minute interval
are often close to zero. As a consequence, charges based on energy and/or 15-minute
peak demand may fail to adequately measure—and attribute costs to—a customer’s use
of ancillary services. One intervener suggested that ancillary service charges to dualuse customers could be charged based on both the load and the generation at the
customer’s site, or that operating reserves could be charged based on a minimum load
factor based on the highest usage.
In its decision the Board ruled that, because voltage collapse would be disastrous for
both generation and load customers, ancillary service charges should be split 50/50
between the two customer classes. The Board agreed that operating reserves would be
provided largely through hourly markets and that the cost would vary by hour. Noting
that payments to providers would reflect energy-market opportunity costs, the Board
ruled that the charges should be energy-based. Energy-based charges had the added
advantage of not increasing the risk in the pending PPA auction. In the case of
transmission constrained on (also referred to as transmission must-run or TMR) costs,
the Board noted that TMR is a substitute for wires and should be paid for by both
generation and load customers. Since TMR costs were incurred on an energy basis, they
should be recovered that way.
The sole exception to the allocation just noted was for voltage control. The Board ruled
that, because voltage control is crucial to load, and because the associated costs are fixed
and do not vary with pool price, voltage control costs should be charged 100% to load
customers on a 100% demand basis.
With respect to dual-use customers, toe Board ruled that they should pay loadapplicable rates for the on-site load capacity plus generator-applicable rates for total onsite generation. Billing on this basis is known as “gross billing”.
3.3 Decision 2001-32: EAL 2001 GTA
On 2000 May 25, the Transmission Administrator filed an application for the 2001 test
year. From the ancillary services perspective, the most important of the numerous
Board decisions arising from this application is Decision 2001-32.24
24
Alberta Energy and Utilities Board. Decision 2001-32: ESBI Alberta Ltd. 2001 General Tariff Application—
Part H: Phase II Matters. 2001 May 18.
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3.3.1 Short Interval Demands
The first ancillary service issue addressed by the Board was that of short-interval
demands (“SID”).25 EAL asserted that allocating ancillary service costs to dual-use
customers on a gross billing basis would be unfair and would require unwanted
intrusion into customers’ businesses, and proposed SID as an alternative. SID would
measure what a customer actually “looks like” to the system on a time scale that was
very near to the system’s natural dynamic response characteristic, thus providing a more
reasonable measure of ancillary service consumption than gross billing could. EAL also
suggested that SID would be useful for capturing the consumption of ancillary services
by customers whose power injections or withdrawals vary significantly over sub-15minute intervals,26 and that one-minute demands were reasonable allocators of local
wires costs.
With respect to applicability, EAL noted that, conceptually, SID metering could be
applied to all customers. However, since 15-minute and 1-minute metering are likely to
give the same results for most customers, there was no need to spend money on
additional equipment. In circumstances where the 15-minute and 1-minutes results are
different, that in itself would be sufficient evidence that SID metering was appropriate.
Some parties disagreed with EAL’s assessment that gross billing was unworkable.
Other parties supported the SID concept, but with qualifications: most restricted their
support to ancillary service (and not wire) cost allocation, while another suggested that
SID should not be applied to multiple-customer points of delivery. Almost all parties—
including EAL—suggested that further study would be necessary before passing final
judgement on SID’s applicability. Several parties urged the TA to perform the further
studies it had indicated were planned, and to “engage in meaningful consultations with
stakeholders well in advance of its next tariff application.”27
Another issue was demand ratchets. Whereas the transmission tariff provides for a 5year ratchet on a load (Rate DTS) customer’s billing capacity, some parties suggested
that either a 1-year ratchet period, or no ratchet period at all, would be appropriate for 1minute demands. The rationale was that ancillary services by their nature are short in
duration, with a significant portion related to activity on the system on an hourly, daily,
or monthly basis.
In its ruling, the Board approved the use of SID metering for the determination of
demand and energy charges for ancillary services. The Board ruled that the TA could
use 1-minute metering for demand charges associated with the Poplar Hill plant and
ILRAS, and for energy charges associated with operating reserves, generator RAS and
black start, load following, and voltage control (including TMR and hydro motoring).28
25
Decision 2001-32, Section 2.1.
26
Examples of loads that vary significantly in sub-15-minutes periods include drag lines and arc furnaces.
27
Decision 2001-32, p. 22.
28
Ibid., p. 36 and 37.
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The Board also ruled that there should be no demand ratchets applied to demandrelated ancillary service charges.
The Board considered that SID metering is consistent with the objective of allocating
demand-related costs on the basis of cost causation. However, the Board agreed with
EAL that the merits of the SID proposal should be studied further before adopting it for
the purposes of metering demand for wire services. Accordingly, the Board directed the
TA to study the merits of using SID metering to meter the demand to be used for all
demand-based rate schedule wire charges and to file the study with its 2003 GTA. 29
3.3.2 Allocation and Classification of Ancillary Services
A number of other issues were raised by parties in connection with the allocation of
ancillary service costs. These issues included:
• the appropriate classification of costs as energy-related or demand-related;
• the allocation of costs over all hours or on-peak hours only;
• the division of cost responsibility between generation customers and load customers.
In its ruling, the Board reiterated the general principle that both generators and loads
benefit from a safe and reliable system.30 Consequently, most ancillary service costs
were allocated equally to generation and load customers. The Board also noted that the
cost of ancillary services may differ depending on whether they are procured in on- or
off-peak periods, and therefore approved a pool price multiplier that recognizes that
fact. The time-varying nature of most ancillary service costs also led the Board to
classify most ancillary service costs as being 100% energy related. The exceptions to the
100% energy classification are: (i) Poplar Hill costs, which were incurred on a fixed basis,
and which were therefore classified as 100% demand; and (ii) ILRAS costs, which were
classified as 60% demand and 40% energy on the grounds that ILRAS behaves
sufficiently as a wires system. These two exceptions were allocated 100% to load
customers since Poplar Hill provides reactive power to support northwest loads, while
ILRAS allows an increase in import capacity on the BC tie, providing additional energy
in times of constraint and placing downward pressure on energy prices.
The following ancillary service cost allocations resulted from the Board’s deliberations:
29
Ibid., p. 33.
30
Ibid., p. 57.
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Generator/Load
Allocation
Demand/Energy
Allocation
Reserves, Generator RAS, Black Start, and Load
Following
50/50
100% energy
Voltage Control – TMR and Hydro Motoring
50/50
100% energy
Voltage Control – Poplar Hill
100% to load
100% demand
Remedial Action Schemes
100% to load
60% demand,
40% energy
Ancillary Service
3.3.3 Future Studies
In its decision, the Board noted the concerned expressed by virtually all parties that the
allocation of ancillary service costs requires more research. The Board also noted that
EAL had proposed to conduct a cost of service study for ancillary services in which
opportunities for unbundling and self-supply of those services would be studied. The
Board considered that the completion of such a study is essential to the development of
proper allocation factors for ancillary services. At page 58 of Decision 2001-32, it wrote:
Therefore, the Board directs EAL, in the 2003 GTA, to file a more detailed and accurate
cost of service study for [ancillary] services. Further, the Board directs that this cost of
service study should contain the rationale for the allocation of each one of the following
[ancillary service] cost components:
•
Operating Reserves (including
supplemental reserves)
regulating
reserves,
spinning
reserves
and
•
Generator RAS and Black Start
•
Load Following
•
Voltage Control (including TMR/SMR, hydro motoring, and ATCO Power’s Poplar
Hill’s plant)
•
Remedial Action Schemes (including ILRAS)
The Board also directs EAL, in the 2003 GTA, to include rate proposals for unbundling
[ancillary services] and proposals for customer self-supply of [ancillary services].
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4 OPERATING RESERVE COSTS AND REVENUES
This section presents an analysis of the prices that transmission customers pay under the
existing rate design31 for regulation, spinning reserve, and supplemental reserve. These
three services, which collectively make up the AESO’s operating reserves (“OR”), are
procured for the most part through the ancillary services market. The intent of this
analysis is to determine how well the revenues received by the AESO track the costs
incurred. The analysis does not consider the appropriateness of the billing determinants
against which the prices are applied;32 such consideration is left to Section 6 (for
regulation) and Section 7 (spinning and supplemental reserves).
4.1 Prices in the Ancillary Services Market
A large percentage of the AESO’s purchases of regulation, spinning reserve, and
supplemental reserve are made through the ancillary services market. Two forms of
each service are used. Sellers of the active form are called on by the System Controller to
provide the specified service during the hours stipulated in the transactions with the
AESO. Sellers of the standby form are called on by the System Controller only if there is
a shortage of active reserves, which could occur if a reserve-supplying unit is forced off
or de-rated, or if more of the service is required than was forecast.
The remuneration an active-reserve seller receives in an hour is equal to the MW·hr33 of
regulation range or spinning/supplemental reserve capacity provided to the AESO
times the sum of the pool price and an index price. The index price, which is usually
negative (i.e., it represents a discount from pool price), is a market-clearing price that is
fixed at the time a transaction is completed. Since the reserves supplied to the AESO in a
given hour may have been purchased at any active-market closing as many as five
business days in advance of the delivery date, there may be several different index
prices pertaining to that hour.
A standby reserve seller receives a two-part payment. The first part, the premium, is paid
for each MW·hr of standby capacity made available to the AESO regardless of whether
the provider is called on by the System Controller. The seller receives the second part,
the activation payment, for each MW·hr of reserve activated by the System Controller. The
activation price is currently a fixed number established at the time a standby transaction
31
The rate design used in the analysis assumes 100% of OR costs are allocated to load customers. The
existing tariff actually allocates the costs 50/50 between supply (STS) and load (DTS) customers.
However, the form of the rate for DTS and STS customers is identical, with the difference in rates
attributable to differing aggregate volumes. As a result, the use of STS charges in the analysis would
make no material difference to the results. Further, the Department of Energy’s transmission policy
suggests that charges to generators will be discontinued, and it is useful to examine the existing rate
design in that context.
32
Under the existing tariff, the billing determinant for operating reserves is energy.
33
“MW·hr” is used to denote one MW of ancillary service capacity for one hour; this is to be contrasted
with “MWh”, which is used to denote one megawatt-hour of energy.
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closes, though consideration is being given to allowing index-based activation
payments.
The total cost of operating reserves purchased through the ancillary services exchange in
an hour is the sum of the amounts paid to active providers, the premiums paid to
standby providers, and the activation payments (if any) made with respect to activated
reserves.
4.2 Hourly Operating Reserve Costs
Figure 4.1 is a graph of the hourly cost of market-purchased OR in 2002. Figure 4.2 is a
“close-up” of the costs for the period from October 15–31, 2002. Both figures
demonstrate that OR costs are extremely volatile; in fact, OR costs are more volatile than
pool prices.34
Figure 4.1: Hourly operating reserve costs for 2002.
700
Hourly Cost [k$]
600
500
400
300
200
100
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Month (2002)
34
The coefficient of variation (the ratio of the standard deviation to the mean) for 2002 OR costs was 2.09
compared to 1.47 for pool prices.
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Figure 4.2: Hourly operating reserve costs for the last half of October, 2002.
100
Hourly OR Cost [k$]
80
60
40
20
0
15
16
17
18
19
20
21
22
23
24
25
26
27
27
28
29
30
31
Date (October 2002)
The total cost of market-purchased operating reserves in 2002 was approximately $168
million,35 which represented approximately 70% of the total cost of ancillary services,
and which added approximately $3.25 to the cost of each MWh of electricity delivered to
DTS customers.36
4.3 A Comparison of Costs and Revenues
From a rate design perspective, the relationship between the costs incurred by the AESO
and the recovery of those costs from customers is of particular interest. Under the
existing tariff, a customer’s charge for OR in each hour is the product of the energy
produced or consumed and a fixed percentage of the hourly pool price. That is,
(4.1)
Customer Charge = r × ( Hourly Energy ) × ( Pool Price) .
35
The costs used in the analysis presented in this section represent only the costs of market-purchased
operating reserves. Operating reserves purchased through other means, such as through the OTC
market, are not included. Such other purchases represented less than 10% of the total OR costs.
36
Note that, in 2002, ancillary service costs were actually paid by both supply and demand customers.
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The percentage rate for each of the generation and load customer groups is calculated
using
(4.2)
r=
(total cost of reserves allocated to customer group)
,
( weighted average pool price) × (total group energy )
with each of the variables in the formula being based on the AESO’s forecasts for the
relevant period (e.g., a year). For 2002, had OR been charged 100% to DTS customers37
and had the AESO’s forecast been perfect, then the tariff rate would have been
r=
$149,342,752
= 6.39% .
$45.74 / MWh × 51,058,575 MWh
Thus, a customer consuming 25 MWh in an hour in which pool price was $50/MWh
would have paid an OR charge of
6.39% × $50/MWh × 25 MWh = $79.88.
Since OR costs vary hourly, it is appropriate to examine the hourly match between costs
and revenues. To do so, hourly revenues were calculated using
(Revenue)h = 6.39% × (DTS MWh)h × (Pool Price)h.
Figure 4.3 is a time series showing the revenue/cost ratio for each hour of 2002;
Figure 4.4 shows the ratio’s frequency distribution. (Note the logarithmic scale used in
these figures). It is obvious from the two charts that the revenue/cost ratio was
frequently a long way from the desired value of 1. Hourly revenues ranged from less
than one tenth to more than 20 times the hourly costs incurred by the AESO and, in
many hours, revenues were less than half or more than double the costs. Such frequent,
large deviations from 1 demonstrate that the match between hourly revenues and
expenses was generally poor and that there was a great deal of uncertainty around the
costs. Forecasting under such conditions is extremely difficult for both the AESO and
for customers that may face deferral account reconciliations and/or rate riders.
Not only did revenues deviate considerably from costs in many hours, but the
distribution of those deviations changed considerably through time, as shown by
Figures 4.1 and 4.6. The latter shows the distributions for the months of January, June,
and December. The significant change over time in the frequency distributions means
37
A precise analysis of the relationship between costs and revenues for 2002 would require using both STS
and DTS volumes and rates in the calculations. However, the DTS and STS rate structures are the
same—both collect using a fixed percentage of pool price times energy injections or withdrawals—and
the fixed percentages are designed to collect 50% of the OR cost from generation customers and 50%
from load customers. Thus, little would be gained through the additional effort required to incorporate
STS-related calculations.
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that there are cost shifts that are not being captured in the annual rate, and reiterate the
difficulty of making reasonable forecasts.
Another problem with the existing rate structure is evident in Figure 4.7, which shows
the calculated cumulative variance between costs and revenues throughout 2002 (solid
line).38 Such large variances can lead to the use of either retroactive or prospective rate
adjustments; the former create unexpected “surprises” for customers, while the latter
recover past costs from future customers. Had the AESO had perfect foresight of actual
annual costs, pool prices, and DTS volumes for 2002, there would still have been a
significant under-collection through the first half of the year and a significant overcollection (to make up for the first-half shortfall) in the second half of the year. Even
allowing for the use of quarterly rate adjustments, in which rates for the next quarter are
derived based on the previous quarter’s results, the possibility for large variances still
exists (see the dotted line in Figure 4.7). With (plausible) quarterly adjustments, the
AESO would have ended the year with a surplus and the need to refund over-collections
(i.e., more rate adjustments).
Figure 4.3: The hourly revenue/cost ratio for 2002.
Revnue:Cost Ratio (Log Scale)
1.50
31.62
10.00
1.00
3.16
0.50
1.00
0.00
-0.50
0.32
-1.00
0.10
0.03
-1.50
1
2
3
4
5
6
7
8
9
10
11
12
Month (2002)
38
Recall that this section contains only costs of market-based ancillary services and “would have been”
revenues, and ignores any rate riders invoked by the AESO. Consequently, a direct comparison with the
AESO’s actual variances would not be meaningful.
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Figure 4.4: The frequency distribution of the hourly revenue/cost ratio.
250
Number of Hours
200
150
100
50
0
0.10
0.18
0.32
0.56
1.00
1.78
3.16
5.62
10.00
Revenue/Cost Ratio (Log Scale)
Figure 4.5: The frequency distributions of the hourly revenue/cost variance for
2002.
1200
Number of Hours
1000
800
600
400
200
0
-40
-30
-20
-10
0
10
20
Hourly Variance [k$]
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Figure 4.6: The frequency distributions of the hourly revenue/cost ratio for three
individual months in 2002.
Relative Frequency
January
0.10
December
June
0.18
0.32
0.56
1.00
1.78
3.16
5.62
10.00
Revenue:Cost Ratio (Log Scale)
The extent of the cost shift among customers that results from the “hindsight” rate is
shown in Figure 4.8. The values shown in the chart are the fraction of the actual costs
paid from the start of the year to the date of exit by customers exiting the transmission
system, and from the date of entry and the end of the year by customers entering the
system. As expected, the fact that there was a revenue shortfall until the end of the year
means that customers leaving the system would not have had time to pay their full share
of OR costs, while customers entering the system would have overpaid as the AESO
recovered shortfalls from the first part of the year.
Another way of looking at OR costs for 2002 is to examine the rates that would have
been required in each hour to balance revenues and costs. The hourly OR cost per MWh
of DTS energy is shown in Figure 4.9, while the hourly OR cost per MWh of DTS energy
as a fraction of pool price is shown in Figure 4.10. The volatility demonstrated in these
charts provides yet another demonstration that neither a fixed per-MWh charge nor a
fixed percentage of pool price is likely to match costs and revenues particularly well.
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Figure 4.7: The cumulative variance under the existing rate and two plausible
variations thereof.
20
Cumulative Variance [M$]
15
Existing Rate with Rate Riders
10
5
0
-5
"Hindsight"
Rate
-10
-15
-20
-25
1
2
3
4
5
6
7
8
9
10
11
12
Month (2002)
Figure 4.8: The ratio of charges to costs for customers leaving or arriving on the AIES
in 2002.
1.5
1.4
Charge:Cost Ratio
1.3
Arriving Customer
1.2
1.1
1.0
0.9
0.8
Departing Customer
0.7
0.6
0.5
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Month (2002)
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Figure 4.9: OR cost per DTS MWh for 2002.
0.12
OR Cost per DTS MWh [$]
0.10
0.08
0.06
0.04
0.02
0.00
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Month (2002)
Figure 4.10: OR cost per DTS MWh as a fraction of pool price.
OR Cost per DTS MWh [$]
1.0
0.8
0.6
0.4
0.2
0.0
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Month (2002)
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Figure 4.11 illustrates another problem with the current rate design. It shows the
average cost of operating reserves per DTS MWh, by hour of the day for 2002, as a
fraction of pool price. The per-unit OR costs as a fraction of pool price are generally
lower during on-peak hours than during off-peak hours, which means that using a fixed,
all-hours rate over-charges customers in on-peak hours and under-charges them in offpeak hours.
Figure 4.11: The average cost of operating reserves per DTS MWh, as a fraction of
pool price, by hour-ending for 2002.
0.09
Average Fraction of Pool Price
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.00
1
3
5
7
9
11
13
15
17
19
21
23
Hour of the Day
4.4 Why Costs and Revenues Don’t Match
The above analysis shows that the OR rate currently in effect does not track actual costs
very well. To see why, we can look at the individual components of the OR cost and
their relationship to the revenues generated by a fraction-of-pool-price rate. The details
of the analysis are given in Appendix A. In summary, that analysis shows that the
following factors lead to the sometimes-large deviations between hourly costs and
hourly revenues.
• Forecasting costs in a volatile pricing environment is very difficult, and the
inevitable forecast errors lead to errors in the rates established under the tariff.
• Market-based operating reserve purchases may be made up to five days in
advance of delivery. Forecast errors may result in higher OR-to-energy ratios
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(which imply higher costs per DTS [or STS] MWh) or the activation of standby
resources (which incurs activation costs).
• The inability of active OR providers to deliver when called on by the System
Controller requires the activation of standby resources; the volume of such
activations is inherently unpredictable, and the associated activation costs are
volatile.
• All of the prices that drive OR costs, including pool prices, active index prices,
standby premiums, and activation prices, are volatile and not necessarily
correlated with each other.
• Required operating reserve volumes do not vary in direct proportion to energy
injections or withdrawals. Coupled with the larger discounts available in on-peak
periods because higher-cost units are on line, this leads (on average) to overrecovery of costs in on-peak periods and under-recovery of costs in off-peak
periods.
The existence of these factors means that the revenue/cost ratio in any hour is a random
variable. There are some alternative rate designs that can dampen or even eliminate this
randomness. As with any rate design, however, such alternatives involve a number of
trade-offs that must be carefully examined to determine whether the alternatives are in
the public interest.
4.5 Additional Comments on the Existing Rate
The fact that the existing OR rate does not track actual costs particularly well should not
be taken as a criticism of either the AESO or the existing rate. When reviewing the
existing rate, several things must be kept in mind.
• The existing rate was developed in an environment that was quite different from the
one that exists now. When the Board first approved a percentage-of-pool-price rate
for OR,39 the vast majority of ancillary services were procured from regulated
generators operating under the legislated hedges. There was no ancillary services
market.
• While the match between costs and revenues over short time scales (e.g., hourly,
daily) may not be very good, the existing rate correctly recognizes that there is a
positive correlation between energy prices and OR costs over longer time intervals.
This can be seen in Figure 4.12, which shows the monthly cost of OR (columns, left
39
Alberta Energy and Utilities Board: Decision 2000-34, ESBI Alberta Ltd. Phase I & II 1999/2000 General Rate
Application, Second Refiling. May 26, 2000.
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scale) and the monthly average pool price (line, right scale). There is a clear tendency
for OR costs to rise as pool prices rise and fall as pool prices fall.
The correlation between monthly average pool prices and monthly OR costs is only
48%. Part of the reason for the relatively weak correlation is a positive one from the
perspective of those parties that must pay for ancillary services. As the ancillary
services market matures, it appears to be driving increased competition and lower
relative prices. The lower relative prices are evident in Figure 4.13, which shows the
monthly OR cost per DTS MWh as a fraction of pool price for 2002 and 2003.
• The match between costs and revenues is not the only criterion by which rates should
be judged.40 Until a new OR rate design is proposed, debated, and approved by the
Board, it cannot be concluded that there is a superior alternative to the existing rate.
• The OR rate design depends heavily on the way(s) in which the AESO procures and
pays for OR. The ancillary services market is not yet three years old and is still
evolving. Before now, there was insufficient operational experience with the market
to justify significant changes to existing rate designs.
$25
$100
$20
$80
$15
$60
$10
$40
$5
$20
$-
Monthly Avg Pool Price [$/MWh]
Total OR Cost [M$]
Figure 4.12: Monthly OR costs and average pool prices for 2002 and 2003.
$0
Jan
Apr
Jul
Oct
Jan
Apr
Jul
Oct
Month (2002, 2003)
40
For some of the other rate design criteria, see: Alberta Energy and Utilities Board: Decision 2000-01, ESBI
Alberta Ltd. – 1999/2000 General Rate Application, Phase 1 and Phase 2, February 2, 2000 (Section 7).
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Figure 4.13: OR cost per DTS MWh as a fraction of pool price.
0.1
0.09
OR Cost per DTS MWh
(fraction of pool price)
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0
1
4
7
10
13
16
19
22
Month (2002, 2003)
4.6 Conclusion
For the most part, the AESO’s operating reserve costs are determined through the
ancillary services market. As one might expect, these costs are volatile and their
distribution changes significantly over time as market conditions change. Neither the
current rate design, nor a rate design having a fixed cost per DTS MWh, provide a good
match between costs and revenues on an hour-to-hour basis. Forecasting under such
conditions is extremely difficult for both the AESO and for customers, who may face
deferral account reconciliations and/or rate riders. As well, there may be temporal cost
shifts among customers.
Alternative rate designs, which may provide better
cost/revenue matching while retaining other important attributes of a sound rate
design, should be considered.
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5 BILLING DETERMINANTS FOR REGULATING RESERVES
In the previous section, the relationship between costs and revenues for operating
reserves was examined; the conclusion was that the existing OR charges do not track
costs very well. The assumption inherent in the existing rate is that energy consumption
is the appropriate billing determinant. On the other hand, it was also concluded that
revenues and costs do not match in part because ancillary service volumes are not
directly proportional to energy consumption. This section examines the assumption that
energy is an appropriate billing determinant for regulation and load following costs and
presents an alternative. The next section looks at spinning and supplemental reserves.
5.1 Regulation Requirements for Individual Loads
Consider a simple power system that consists of a generator (G1) and a load (L1). If it is
assumed that the load is perfectly steady at 100 MW, then the generator’s output must
also be steady at 100 MW. (For the purposes of this example, all components in the
system are lossless and perfectly reliable.)
Assume now that a second load (L2), with consumption that varies randomly between 70
and 75 MW, is added to the system. Since injections and withdrawals must balance,
there must be at least one generator with the ability to vary its output in response to the
changing load. To meet the requirement, a second generator (G2) is added to the system.
It has a minimum output level of 30 MW and is equipped with an automatic generation
control (“AGC”) system that adjusts the unit’s output to track the variations in load. The
loads’ power requirements are now met with the G1 producing 140 MW and G2
producing between 30 and 35 MW. Since G2 must be able to adjust its output level
anywhere within a 5 MW band, it is supplying 5 MW of regulation range and 30 MW of
“energy market” output. Thus, the addition of L2 has caused the system’s regulation
requirement to go from zero to 5 MW. Figure 5.1 shows the total load at one-minute
intervals over an hour, along with the regulation range.
A third load (L3), whose consumption varies between 25 and 40 MW, is now added. The
energy market dispatch in this case is 100 + 70 + 25 = 195 MW. By itself, L3 would
require 15 MW of regulation range. However, when the required regulation range is
calculated as the maximum difference between the total load and the energy market
dispatch (see Figure 5.2), the result is 18.7 MW instead of 5 + 15 = 20 MW. The reason is
that the peaks in L2 and L3 do not coincide (i.e., the loads are not perfectly correlated).
This is analogous to the fact that AIES peak demand is less than the sum of the peak
demands at the individual substations because of load diversity.41
41
It can be shown that, if there are n uncorrelated loads, each with a required regulation range of r MW,
the expected value of the regulation range of the total load is r √n MW.
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Figure 5.1: Total load (L1+L2), energy market dispatch, and regulation range for the
example system.
176
Regulation
Range
Load [MW]
174
172
Energy Market Dispatch Level
170
168
0
10
20
30
40
50
60
Time [Minutes]
Figure 5.2: Total load, energy market dispatch, and regulation range following the
addition of L3.
215
Load [MW]
210
Regulation
Range
205
200
Energy Market Dispatch Level
195
190
0
10
20
30
40
50
60
Time [Minutes]
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For cost allocation purposes, it seems reasonable that a customer with a more variable
load should assume responsibility for a greater share of the regulation volume than a
customer with a less variable load. A pro rata allocation based on the individual
regulation ranges can be used, with the result that L1 would be responsible for
0/(0+5+15) = 0%, L2 would be responsible for 5/(0+5+15) = 25%, and L3 would be
responsible for 15/(0+5+15) = 75%. Note that the loads’ responsibilities for regulation
range are not related to their energy consumption; in fact, the largest energy consumer in
this example has the smallest regulation requirement, while the largest regulation
requirement is associated with the customer consuming the smallest amount of energy.
As noted in Section 2, a load can be thought of as having slowly varying (slow) and
rapidly varying (fast) components. Each of the loads introduced thus far has had a fixed
slow component. The next load to be introduced, L4, has a slow component that rises
from 100 MW to 200 MW over the course of an hour (see Figure 5.3).
Figure 5.3: Load L4 and the associated energy market dispatch.
220
L4
200
Load [MW]
180
Slow Component of L4
160
AGC
140
Energy Market Dispatch
120
100
80
0
10
20
30
40
50
Time [Minutes]
The share of regulation range allocated to L1, L2, and L3 was based on the maximum
difference between their measured values and the associated energy market generation.
The same is true for L4. In L4’s case, however, the energy market generation is not
constant because the System Controller would dispatch additional generation to follow
the rise in L4’s slow component. A hypothetical energy market dispatch is shown in
Figure 5.3. L4’s regulation range, which is calculated as the difference between the
measured load and the energy market dispatch, is found to be 18.9 MW. The sum of the
loads’ regulation ranges is 0 + 5 + 15 + 18.9 = 38.9, so the regulation range allocation
with L4 included is: L1, 0%; L2, 5/38.9 = 12.9%; L3, 15/38.9 = 38.5%; and L4,
18.9/38.9 = 48.6%.
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5.2 Calculation of Regulation Billing Determinants
The calculation of the regulation ranges associated with each load in this example was
simple because it was assumed that the energy market dispatches associated with L1, L2,
and L3 were fixed, and that all changes in the dispatch were associated with L4. In fact,
many different assumptions about how much of a load is served by the energy market
are possible. Consider the two assumptions for L3 shown in Figure 5.4. Clearly, the
dashed line results in a much different value for the regulation component than does the
dotted line (15 and 8 MW, respectively). Fortunately, a mechanism that points to the
“correct” choice is available. A particular moving average calculation, which can be
derived from the characteristics of AIES load and the output of regulating units, is used
to split metered loads into regulation and energy-market components.
Figure 5.4: Two possible assumptions about the energy market component of L3.
45
Load [MW]
40
35
30
25
Alternate assumptions about the energy market component of L3
20
1
11
21
31
41
51
Time [Minutes]
Basically, the filter computes a moving average that results in a smooth curve roughly in
the middle of the rapid up-and-down movements of the load (see the top chart in Figure
5.5). The smooth curve is a proxy for the energy market dispatch associated with the
load.42 The difference between the metered values and this proxy dispatch is deemed to
come from the regulation units, and the difference between the maximum and minimum
regulation values over an hour is the load’s regulation range (see the bottom chart in
Figure 5.5).
42
There is a slight difference here from the example, but all it amounts to is measuring regulation as
positive or negative movements from the midpoint of the regulation range rather than as positive-only
movements measured from the bottom of the range. It should be clear that the two approaches result in
identical values for the regulation range associated with a load.
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Figure 5.5: The calculation of a load’s regulation range in each of three hours.
50
45
Load [MW]
40
35
30
Moving Average
Metered Values
25
20
0
20
40
60
80
100
120
140
160
180
120
140
160
180
Time [Minutes]
6
4
Load [MW]
2
0
-2
-4
Regulation Range
-6
-8
0
20
40
60
80
100
Time [Minutes]
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5.3 Standards Governing Alberta Regulation Requirements
In the example given in the previous section, the sum of energy market generation and
regulating generation exactly balanced the total load at all times. In reality, deviations
between real and “perfect” regulation levels are inevitable in Alberta and in
neighbouring control areas. Such deviations result in differences between scheduled
and actual interconnection frequency and between scheduled and actual tie line flows.
To ensure that interconnection frequency and tie-line flows are managed effectively, and
that control areas do not operate in a way that would adversely affect their neighbours,
the North American Electric Reliability Council (“NERC”) establishes rules that
interconnected transmission system operators must comply with.
The area control error (“ACE”) is an indicator of the imbalance between a control area’s
injections (generation and scheduled imports) and withdrawals (control area load,
exports, and losses). ACE is zero when the two are perfectly matched.43 However,
because injections and withdrawals change randomly, it is impractical for a control area
to maintain a zero ACE at all times. Transiently, small imbalances are usually
acceptable, as are occasional large ones. NERC Policy 1A sets two Control Performance
Standards, CPS1 and CPS2, that establish statistical limits on ACE magnitudes. CPS1 sets
the allowable distribution of a control area’s one-minute ACE values on a rolling 12month basis. CPS2 states that at least 90% of the 10-minute-average ACE values in each
calendar month must be less than a specified, control-area-specific value.
The regulation range that the AESO has determined to be necessary to comply with
CPS1 and CPS2 are set out in Operating Policy OPP-401, Regulating Reserve Service.
Table 1 in that document establishes a minimum regulation range of 110 MW in all
hours, and allows for additional regulation range during high system demand ramps.
These large ramps typically occur during the morning and evening hours, but may also
occur when there is a large swing in flows on the BC tie as it changes from imports to
exports or vice versa.
As noted in a previous section, several Alberta generators assume the responsibility—
via exchange-traded or over-the-counter (“OTC”) contracts with the AESO—of
increasing or decreasing their power outputs in response to signals provided by the
System Controller’s AGC system. That system calculates the changes in generation
necessary to move ACE toward zero (i.e., to restore the supply/demand balance) and
signals the regulation-providing generators accordingly. Thus, regulation service can be
viewed as the service that seeks to maintain ACE within acceptable limits.44
43
The ACE value also indicates whether the control area is meeting its obligation to help maintain system
frequency. Technically, ACE is zero when scheduled and actual interchanges are equal and system
frequency is at its scheduled value (usually 60±0.02 Hz.)
44
Additionally, tie line flows change in response to changing injection/withdrawal balances in a control
area. Tie lines therefore contribute to the balancing action provided by AGC units.
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5.4 Regulation Volumes
In designing the rates to charge for particular ancillary services, it is necessary to know
what the cost and volume drivers are. The cost of operating reserves (regulation,
spinning reserve, and supplemental reserve) in aggregate was examined in Section 3,
where it was found that the revenues derived from the existing tariff rate structure do
not track OR costs very well. Mechanisms for improving the cost/revenue matching are
discussed in a separate report. In this section, regulation volume requirements are
analyzed to determine whether there are any volume-related features that should be
incorporated in the rate design.
For the analysis of regulation volumes, more than 500,000 values of regulation down, as
measured at one-minute intervals during 2003, were used. Regulation down (RD) is a
value tracked by the System Controller’s Energy Management System that identifies the
amount of downward movement available to regulation units in aggregate at any point
in time. RD also represents the regulation component of total AIES generation. The
difference between the largest and smallest values of RD in each hour is the regulation
range actually used in that hour (see Figure 5.6).
Figure 5.6: Regulation down over a six-hour period.
180
Regulation Down [MW]
160
140
Regulation
Range
during the
second
hour
120
100
80
60
40
20
0
0
1
2
3
4
5
6
Time [hours]
Figure 5.7 shows the distribution of the hourly regulation ranges for on- and off-peak
hours in 2003, while Figure 5.8 shows those ranges plotted against hourly AIES load.
These figures demonstrate that the regulation range does not depend on either the time
of day or AIES load, lending credence to the suggestion that energy consumption is not
an effective regulation billing determinant. The lack of a relationship between energy
consumption and regulation requirements is another reason why OR revenues, which
are proportional to energy consumption, do not track OR costs very well.
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Figure 5.7: The on- and off-peak AGC range distributions.
0.014
Relative Frequency
0.012
0.01
On Peak
0.008
0.006
Off Peak
0.004
0.002
0
40
60
80
100
120
140
160
180
200
220
240
AGC Range [MW]
Figure 5.8: A scatterplot showing hourly regulation ranges against AIES load.
350
AGC Range [MW]
300
250
200
150
100
50
0
5000
6000
7000
8000
9000
AIES Load [MWh]
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5.5 The Effect on Customers of Changing Billing Determinants
To examine the effect of using regulation range rather than energy as the billing
determinant for regulation charges, one-minute data for 12 AIES load customers was
analyzed. The available data covered three complete one-week periods in 2001 and
2002. When combined with data on the hourly cost of market-procured regulation over
the same three (non-consecutive) weeks, estimates of the charges that would have been
paid by each customer were developed. The results are shown in Figure 5.9.
It is very clear from the chart that some customers (numbers 1 and 11 in particular) pay
considerably more under the existing energy-based allocation than they would under a
range-based allocation. These customers are large users of energy but, since their loads
are not particularly volatile, relatively small users of regulation. Conversely, some
customers (e.g., numbers 6, 7, and 10) consume relatively small amounts of energy but
require large amounts of regulation. While it should be emphasized that the results are
approximate (one-minute data was available for only about 24% of the AIES load), it is
clear that the current, energy-based regulation allocation method results in some
customers paying considerably more or less than they would under a more cost-based
rate.
Figure 5.9: A comparison of energy-based and range-based regulation costs for 12
AIES load customers.
300
Three-Week Cost [k$]
250
200
150
100
50
1
2
3
4
5
6
7
8
9
10
11
12
Customer Number
Energy Basis
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5.6 Billing Determinants for Importers and Exporters
As discussed above, regulation is the ancillary service designed to maintain ACE within
the limits prescribed by NERC policies. A non-zero ACE results when Alberta
generation plus scheduled imports do not match Alberta load (including losses) plus
scheduled exports. Thus, while importers and exporters determine the transactions they
will undertake (subject, of course, to the availability of intertie capacity), it is ultimately
the totality of the generator and load actions, events within the individual control areas,
and the actions of the control area operators themselves, that determine actual line
flows. In other words, the parties who establish the import/export transactions that
occur over the tie lines have little or no control over how closely line flows match their
schedules. Importers and exporters could not, for example, add a piece of equipment to
the transmission system that would smooth out (i.e., reduce the regulation burden
created by) tie line flows. There is little to be gained, therefore, by charging those parties
for regulation based on actual flows.
Charges for importers and exporters based on scheduled flows rather than actual flows
could be considered. There are, however, several arguments against doing so:
• scheduled flows are known in advance, so they do not present the same uncertainty
to the System Controller as most Alberta loads; consequently, less load following is
needed (at least in theory);
• scheduled flows do not exhibit short-term up-and-down movements that must be
tracked by regulation-providing units.
• imports and exports are currently non-firm transactions, and are therefore priced at
a discount to firm transmission service;
• pending government policy45 states that variable charges are ultimately to be
removed from import transactions.
In view of the foregoing, it makes little sense to allocate regulation charges to import or
export transactions.
5.7 Billing Determinants for Dual-Use Customers
A dual-use customer is one that sometimes looks like a load and at other times looks like
a generator. Figure 5.10 shows the injections and withdrawals at a dual-use
transmission connection point. If a perfectly steady load of about 22 MW were added at
that bus, the result would be a pure load, as shown in the bottom curve in Figure 5.11. If
a perfectly steady generator of about 25 MW were added, the result would be a pure
generator, as shown in the top curve in Figure 5.11. In any of these three cases, the
regulation component of the signal is the same. Thus, pure generators, pure loads, and
45
At the time of writing, the (proposed) Alberta Department of Energy policy that will mandate the
removal of charges (other than losses charges) to importers has not yet been enacted in regulation.
this has not been enacted in a regulation under the Electric Utilities Act.
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dual-use customers exhibiting the same variability in generation/consumption create
the same regulation requirements.
In accordance with the aforementioned pending Alberta government transmission
policy, generators are not to be charged for ancillary services. Consequently, any
contribution by a generator to the regulation requirement is effectively ignored. It
therefore makes sense to ignore generators when establishing charges to dual-use
customers. This may be accomplished by separately metering the generation and the
load at a dual-use site. The Board approved the use of such metering in a previous
decision.46
Figure 5.10: The load and generation of a dual-use customer.
Load (-) or Generation (+) [MW]
30
20
10
0
-10
-20
-30
0
1
2
3
4
Time [Hours]
46
Alberta Energy and Utilities Board. Decision 2000-01: ESBI Alberta Ltd. 1999/2000 General Rate Application,
Phase 1 and Phase 2. February 2, 2000. Page 207. See also Alberta Energy and Utilities Board Decision
2001-32, ESBI Alberta Ltd. 2001 General Tariff Application, Part H: Phase II Matters, May 2, 2001, page 35.
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Figure 5.11: The load and generation of a dual-use customer.
Load (-) or Generation (+) [MW]
60
40
Generator
20
0
-20
Load
-40
-60
0
1
2
3
4
Time [Hours]
5.8 Conclusions
The analysis presented in this section shows that regulating reserve costs are driven by
the variability of customer loads, not by their energy consumption. The use of energy as
the basis for regulation charges results in customers with large, stable loads paying more
for regulation than customers with smaller but highly variable loads. Further, since the
AESO’s regulation costs depend on factors other than energy consumption, there is an
unavoidable mismatch between costs and revenues on an hourly basis. A method for
calculating each customer’s contribution to the requirement for regulating reserve
(including the load following component) is available and should be considered for
implementation.
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6 BILLING DETERMINANTS FOR SPINNING AND
SUPPLEMENTAL RESERVES
6.1. Governing Standards
When a generator in Alberta trips unexpectedly, there is a sudden shortage of
generation in the province. If the interconnection to British Columbia and the rest of the
western interconnection is in place, the loss of supply is shared among all generators in
western North America. Power flows in on the tie immediately to cover Alberta’s
shortfall.47 This results in a difference between actual and scheduled tie line flows, a
difference between actual and scheduled frequency (though the frequency deviation
may be very small), and a change to the area control error (“ACE”) .
The North American Electric Reliability Council (“NERC”) Disturbance Control
Standard (“DCS”)48 states that a control area’s ACE must return to zero (or to its predisturbance level) within 15 minutes following the start of a reportable disturbance. In
the western interconnection, which includes the Alberta control area, a reportable
disturbance is one that causes a control area’s ACE to change by at least 35% of the
maximum loss of generation that would result from a single contingency. The
compliance level is 100%—that is, control areas are expected to recover within 15
minutes in every case.49
NERC allows regional councils to establish their own contingency reserve requirements
provided they are more stringent than the NERC DCS requirements. The Western
Electric Coordinating Council (“WECC”) specifies the minimum amount of contingency
reserve that each control area in the western interconnection must carry. The WECC’s
Minimum Operating Reliability Criteria (“MORC”)50 state that the spinning and nonspinning reserves carried shall be sufficient to meet the DCS, and shall be the greater of:
(1)
The loss of generating capacity due to forced outages of generation or
transmission equipment that would result from the most severe single
contingency (at least half of which must be spinning reserve); or
(2)
The sum of five percent of the load responsibility served by hydro
generation and seven percent of the load responsibility served by thermal
generation (at least half of which must be spinning reserve).
The MORC also states that a control area or reserve sharing group must fully restore its
contingency reserves within 60 minutes following the end of the disturbance recovery
period. This may mean re-dispatching reserve-providing generators to their pre-
47
An example is given in Section 2.
48
ftp://www.nerc.com/pub/sys/all_updl/oc/opman/policy1_BOTApproved_1002.doc
49
Exceptions are made in certain cases when one or more events occur within the recovery period of an
initial event.
50
http://www.wecc.biz/MORC_Pages_9-02.pdf
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disturbance outputs, allowing loads that were tripped (as supplemental reserves) to
resume pre-disturbance operations, and/or dispatching new reserve suppliers.
Alberta’s contingency reserve requirement is equal to the amount given by (2) above (i.e,
the “five and seven” rule) approximately 90% of the time. The other 10% of the time,
either the import level (adjusted for load that could be tripped off in the event of a
problem on the interconnections) or the most severe single generation contingency
determines the required level of contingency reserves. Details can be found in AESO
Operating Policy OP-402, Supplemental and Spinning Reserve Services.
6.2 Volume Requirements
As noted above, the volume of contingency reserve that the Alberta control area must
carry is based on firm load responsibility (“FLR”) approximately 90% of the time. The
FLR is calculated in accordance with AESO Operating Policy 406, Firm Load
Responsibility. The value is calculated in near-real-time to ensure reasonably accurate
values at all times, and is posted on the AESO’s website in the Current Supply and
Demand report.
The fact that the volume of operating reserves procured by the AESO is directly related
to AIES (firm) energy consumption51 in most hours suggests that the use of a load’s
energy consumption as its contingency reserve billing determinant is appropriate.
6.3 Charges under the Existing Tariff
It was shown in Section 4 that hourly operating reserve revenues and costs do not match
very well under the existing tariff. Part of the reasons for the mismatch, as discussed in
Section 5, is that operating reserve charges are based on energy consumption, which is
not a good measure of regulation requirements. Since energy is the right measure of
contingency reserve requirements, the following question arises. Would removing the
regulating reserve component of operating reserves allow the existing rate design to
work well for spinning and supplemental reserves? Unfortunately, the answer is no.
Had contingency reserves been separated from regulating reserves in 2002, the charge to
loads as a percentage of pool price would have been
$90,984,767
= 3.90%.
$45.74 / MWh × 51,058,575 MWh
on a “hindsight” basis. (Note that this value is based strictly on the costs incurred
through the ancillary services market.)
51
Since OR purchases may be made up to five days in advance of the delivery hour, real-time
requirements may differ from the AESO’s advance purchases. The requirement to call on standby
reserves may also cause the final hourly volume to deviate from the volume calculated in accordance
with WECC rules. These factors do not change the appropriateness of energy consumption as the
contingency reserve billing determinant.
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The two figures below show the hourly contingency reserve revenue/cost ratio and the
cumulative revenue/cost variance for 2002, respectively. They show that unbundling
contingency reserve costs from regulating reserve costs does not alleviate the problems
with the existing OR rate design, as discussed in Section 4.
6.4. Conclusion
The analysis above indicates that hourly energy consumption is the appropriate billing
determinant for spinning and supplemental reserves. In this regard, no change from the
existing tariff is needed. However, setting the price of spinning and supplemental
reserves equal to a fixed percentage of pool price leads to large discrepancies between
the costs paid by the AESO and the revenues it receives from transmission customers.
Therefore, a change in the spinning and supplemental reserve rate structures may be
warranted.
Figure 6.1: The revenue/cost ratio for contingency reserves in 2002.
Revenue/Cost Ratio
100.00
10.00
1.00
0.10
0.01
1
2
3
4
5
6
7
8
9
10
11
12
Month (2002)
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Figure 6.2: The revenue/cost ratio for contingency reserves in 2002.
0
Cumulative Variance [M$]
-2
-4
-6
-8
-10
-12
-14
-16
1
2
3
4
5
6
7
8
9
10
11
12
Month (2002)
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7 VOLTAGE CONTROL COSTS AND REVENUES
Like Section 4, this section contains an analysis of the prices that transmission customers
pay under the existing tariff, in dollars per billing unit, for certain ancillary services. The
focus here is on voltage control costs, which made up approximately 30% of the AESO’s
total ancillary services budget in 2002.52
7.1 Charges under the Existing Tariff
As described earlier in this report, there are several forms of voltage control used by the
AESO. The real-energy services are provided by IBOC and LBCSO generators, suppliers
under commercial contracts, and (if necessary) by generators in accordance with the
transmission tariff. Reactive power services can be provided by the Poplar Hill facility,
IBOC generators, and LBCSO generators. The associated costs are currently allocated as
follows.
• The IBOC and LBCSO costs are combined with wires costs and allocated 58% to
load customers and 42% to supply customers. Wires costs are recovered from load
customers on a 60% demand and 40% energy basis, while supply customer charges
are based 100% on energy injections. Based on the costs incurred in 2002, and
assuming 100% allocation to load (DTS) customers, the demand-related charge for
IBOC and LBCSO would have been
60% × $3.1M
= $18.06 / MWmonth
102,971 MWmonths
while the energy-related charge would have been
40% × $3.1M
= $0.024 / MWh .
51,058,575MWh
• Commercial and tariff-based TMR costs are allocated 50/50 between supply and
load customers. They are charged to both customer groups on a 100% energy
basis, with the price per MWh being a fixed percentage of pool price. Again,
assuming 2002 costs and 100% allocation to DTS customers, the contribution of
these costs to the pool price percentage rate was
$55.5M
= 2.38%.
$45.74 / MWh × 51,058,575 MWh
• Reactive power costs are allocated in two different ways. The costs for hydro
motoring53 are allocated in the same way as TMR costs: 50% to supply customers
and 50% to load customers, with all costs being recovered on a 100% energy basis
using a specified percentage of pool price. Poplar Hill costs are allocated 100% to
52
For 2003 and beyond, this percentage is expected to be higher because certain forms of voltage control
used in 2002 are no longer required.
53
This service is no longer required by the AESO.
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load customers on a 100% demand basis. The corresponding 2002 rates would
have been
$4.2 M
= 0.18%
$45.74 / MWh × 51,058,575 MWh
for hydro motoring and
$1.9 M
= $18.45 / MWmonth
102,971 MWmonths
for Poplar Hill.
From the figures given above it is clear that TMR costs represent a large fraction54 of the
AESO’s total voltage control cost. Therefore, the following analysis focuses on TMR.
7.2. TMR Arrangements
7.2.1. IBOC Contracts
The IBOC contracts provide incentives for the IBOC generators to produce energy to
offset some of the north-south power flow that, if left unmanaged, can lead to voltage
stability problems in southern Alberta. Under these contracts, if the units produce more
than 70% of a benchmark amount of energy in a month, the owners receive payments of
between 80% and 100% of their respective location-based credits. The credits awarded
to the IBOC generators range between $3.25 and $3.75 per MWh.55 Since IBOC
payments are treated under the tariff as fixed costs56 and are recovered from customers
on the same basis as wire costs, they are not included in the following analysis of hourly
TMR costs.
7.2.2. LBCSO Contracts
Under the LBCSO contracts,57 the service providers receive an annual fixed payment.
The providers also receive a variable payment—equal to a heat rate times a gas price
plus O&M costs, transmission costs, and loss factor credits—that is netted against pool
revenues for the dispatched TMR volumes.
54
Approximately 70% in 2002 and 85% in 2003.
55
Alberta Energy and Utilities Board. Decision 2000-47: ESBI Alberta Ltd. – IBOC Contract Approval, July 12,
2000.
56
The IBOC payments do not depend directly on pool prices, and given reasonable performance by the
IBOC units, should be relatively stable from month to month.
57
Alberta Energy and Utilities Board. Decision 2001-18 (ESBI Alberta Ltd. – Part F: Location Based Credits –
Standing Offer), March 2, 2001.
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7.2.3. Direct Commercial Contracts58
Despite the existence of the contracts noted above, there are still instances in which the
AESO must negotiate directly with suppliers of ancillary services, including voltage
control services. The details of these contracts are confidential.
7.2.4. Tariff Provisions
Under Article 24 of the AESO Tariff’s Terms and Conditions of Service, the System
Controller may require a transmission customer to operate its generating unit(s) to
provide ancillary services (including TMR) during an emergency. If the provider has an
existing contract with the AESO, the terms of that contract will govern the payments the
provider receives for the emergency provision of service. If there is no contract between
the AESO and the provider, the amount per MW-hr to be paid to the provider is the
higher of the following amounts:
(a)
(b)
(c)
(d)
(e)
the amount paid to any other provider of the same service under a contract;
110% of the hourly pool price plus any AESO charges;
the direct costs incurred by the customer to provide the service, plus ten
percent;
the verifiable opportunity cost incurred by the customer to provide the service;
the difference between the customer’s offer price into the pool and the hourly
pool price.
7.3 The General Form of TMR Payments
The variable portion of the TMR payment to a generation owner is usually designed to
keep the owner financially whole when its units are run out of merit. Thus, the AESO’s
hourly payment to a TMR generator usually includes an amount equal to the positive
difference between the variable operating cost of the unit and pool price multiplied by
the unit’s output. For most TMR generators, the operating cost is determined in part by
the product of a heat rate and the price of natural gas.
The most obvious feature of TMR payments of this form is evident in Figure 7.1, which
shows the payments as a function of pool price and gas price for a hypothetical TMR
unit with a fixed payment of $100/hr, an output level of 100 MW, a non-fuel variable
O&M cost of $3/MWh, and a heat rate of 10 GJ/MWh. The payments (solid lines)
increase as gas prices increase but decrease as pool price increases.
For comparison purposes, the figure also shows the revenues (dashed lines) recovered
under percentage-of-pool-price rates at three different load levels (a base level E and
levels 15% above and below that). Unfortunately, the cost curves and the revenue
curves are completely different. At each load level and gas price, there is only one pool
price at which costs and revenues match, and they diverge quickly from each other as
the pool price moves away from that one value. The analysis in the next section
58
The IBOC and LBCSO contracts are direct commercial contracts, but are not included in this category
because they have been dealt with separately.
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confirms that this is so not only in this simple model, but for actual TMR costs and
revenues as well.
Figure 7.1: TMR costs and revenues as a function of pool price for the hypothetical
provider.
8000
TMR Cost or Revenue [k$]
7000
6000
5000
4000
3000
2000
1000
0
0
10
20
30
40
50
60
70
80
90
100
Pool Price [$/MWh]
7.4. TMR Costs in 2002
To examine the relationship between TMR costs and TMR-related revenues, the same
approach as that used in the previous section was taken. The percentage-of-pool-price
rate related exclusively to TMR was calculated using
(7.3)
r=
(total cost of TMR)
.
( weighted average pool price) × (total DTS energy )
Using actual values for 2002,59 the TMR rate was
r=
59
32,171,698
= 1.38% .
45.74 × 51,058,575
The value of r was calculated using only the TMR data used in this analysis. Hourly data was readily
available for approximately 85% of the AESO’s 2002 variable TMR costs.
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This rate is “perfect” in the sense that it is based on actual costs rather than forecasts, so
forecast error has been eliminated as a source of the discrepancy between the costs and
revenues used in this analysis.
Figure 7.2 shows the hourly cost of (the aforementioned subset) of the TMR costs
incurred by the AESO. The costs are quite volatile,60 as would be expected of costs that
depend directly on gas prices and pool prices. They are somewhat less volatile than
pool prices, however, because when pool prices spike, TMR costs drop. This inverse
relationship is confirmed in Figure 7.3, which shows TMR costs and pool prices for a
week in October 2002, and in Figure 5.8, which is a scatter plot of hourly TMR costs
against pool prices.
Figure 7.2: The hourly cost of TMR 2002.
14
TMR Costs [k$/hr]
12
10
8
6
4
2
-
1
2
3
4
5
6
7
8
9
10
11
12
Month (2002)
60
The coefficient of variation (the ratio of the standard deviation to the mean) in 2002 was 0.30 for gas
prices, 0.63 for TMR costs, and 1.47 for pool prices.
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Figure 7.3: Hourly TMR costs in October 2002.
18
100
16
14
50
12
0
10
TMR Costs [k$/hr]
Pool Price [$/MWh]
150
20
8
-50
6
4
-100
2
-150
0
5
6
7
8
9
10
11
12
Day (October 2002)
Figure 7.4: Hourly TMR costs plotted against pool price for 2002.
14
Hourly TMR Cost [k$]
12
10
8
6
4
2
0
1
10
100
1000
Pool Price [$/MWh] (Log Scale)
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The fact that TMR costs are inversely related to pool prices means that, in general, TMR
costs are higher during off-peak periods. Since energy consumption is lower then, TMRrelated revenues are lower, and the revenue/cost ratio drops. During on-peak periods,
the converse is true. Consequently, TMR costs are generally under-collected during offpeak periods and over-collected during on-peak periods, as shown in Figure 7.5. As the
chart shows, revenues are only about 20% of costs during many off-peak hours, while
they are about 300% of costs during many on-peak hours. Figure 7.6 provides another
view of the significant difference between costs and revenues during on- and off-peak
periods; it shows the average hourly revenues and costs, per DTS MWh, by hour of the
day. The current rate structure clearly does not track TMR costs very well.
Because gas prices often appear in the calculation of TMR costs, it might be expected that
factoring them into the tariff rate design may improve the relationship between costs
and revenues. That option may not be as promising as hoped, however. While there is a
positive correlation between daily gas prices and daily TMR costs (see Figure 7.7), it is
not particularly strong, at least in part because neither daily average pool prices nor
TMR volumes are strongly correlated with gas prices.
Figure 7.5: The on- and off-peak distributions of the TMR revenue/cost ratio.
1.6
1.4
Relative Frequency
1.2
1
Off Peak
On Peak
0.8
0.6
0.4
0.2
0
0.0
0.1
0.3
1.0
3.2
10.0
31.6
100.0
Revenue/Cost Ratio (Log Scale)
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Figure 7.6: Average TMR costs and charges by time of day for 2002
(based on sample data only).
Cost/Charge per DTS MWh [$]
1.40
Actual cost per DTS MWh
1.20
1.00
0.80
0.60
0.40
Charge per DTS MWh based on a
percentage-of-pool-price rate
0.20
0.00
1
3
5
7
9
11
13
15
17
19
21
23
Hour Ending
Figure 7.7: Daily TMR costs plotted against daily gas prices for 2002.
300
Daily TMR Cost [k$]
250
200
150
100
50
0
0
1
2
3
4
5
6
7
Gas Price [$/GJ]
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7.5. A Natural Hedge?
Given that OR costs rise as pool prices rise, while TMR costs decrease as pool prices rise,
there is a built-in hedge when TMR and OR costs are considered together. The effect is
illustrated in Figure 7.8 in the hypothetical case of one unit (with the same characteristics
as the unit used for Figure 7.1) providing 100 MW of TMR and another unit providing
500 MW of OR.61 The question is, can this natural hedge be used to smooth some of the
volatility in ancillary services costs?
There is, in fact, no significant benefit to combining OR and TMR costs on either
volatility or cumulative variances, as shown in Figures 7.9 and 7.10. The former figure
shows the distribution of the hourly revenue/cost ratios for OR costs alone and for OR
and TMR costs combined; there is no appreciable difference in the ratio’s variability
between the two cases.62 The latter figure shows the cumulative difference between
tariff revenues and costs, again for OR costs alone and for OR and TMR costs combined.
The absence of any improvement in the variance is clear.
There are several reasons why the hedge does not work in practice, including that TMR
volumes are generally lower than OR volumes (and therefore cannot fully offset OR cost
changes) and that both OR and TMR costs are affected by so many factors other than
pool price.
Figure 7.8: The combined cost of OR and TMR with a 100 MW TMR unit and a 500
MW OR unit.
35000
Gas Price = $5/GJ, Active OR Index = -$25/MW-hr
30000
Gas Price = $3/GJ, Active OR Index = -$50/MW-hr
TMR+OR [$]
25000
20000
15000
10000
5000
0
0
10
20
30
40
50
60
70
80
90
Pool Price
61
The AESO would not actually buy 500 MW of OR from a single unit. 500 MW is used as representative
of the amount of OR that the Alberta control area may have on line in a given hour.
62
The standard deviation changed from 34,276 to 33,583.
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Figure 7.9: The revenue/cost frequency distributions for OR costs alone and for OR
and TMR costs combined in 2002.
2.5
OR only
Relative Frequency
2
1.5
OR+TMR
1
0.5
0
0.06
0.16
0.40
1.00
2.51
6.31
15.85
Revenue/Cost Ratio (Log Scale)
Figure 7.10: The cumulative revenue/cost variances for OR costs, TMR costs, and
the sum of OR and TMR costs for 2002.
Cumulative Variance [M$]
5
-
(5)
TMR only
(10)
OR only
(15)
(20)
OR + TMR
(25)
1
2
3
4
5
6
7
8
9
10
11
12
Month (2002)
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7.6. Conclusions
It is clear that the existing rate design does not create a good match between hourly TMR
costs and revenues. TMR charges are proportional to pool prices, while the AESO’s
TMR payments are roughly inversely proportional to pool prices (at a given gas price).
Since TMR costs make up a significant portion of the AESO’s ancillary services
payments, consideration should be given to developing an alternative rate design that
can track costs more closely (while acknowledging that the degree of matching between
costs and revenues is only one consideration in rate design).
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8 VOLTAGE CONTROL BILLING DETERMINANTS
8.1 Governing Standards and Operating Procedures
The requirements for, and the drivers of, voltage control services vary across the
province. The differences arise for many reasons, including differences in transmission
system configuration, transmission line thermal and stability limits, the proximity of
generation, and the size and type of loads in the area. The AESO develops and
publishes specific operating procedures for these areas.
In the northwest part of the province, which is characterized by very long transmission
lines with little path redundancy, and in which the load is generally significantly greater
than area generation, TMR requirements are determined primarily by area load and
secondarily by voltage requirements on a particular transmission station.63 To manage
northwest voltages, the AESO has access to ATCO Power’s Poplar Hill facility (under
the Poplar Hill contract), ATCO Power’s Valleyview facility (under an LBCSO contract),
and TransCanada Energy’s Bear Creek facility (under an LBCSO contract), and possibly
other confidential commercial contracts.
In the Calgary area, the TMR requirement is also driven by load. In this case, however,
it is the load on the entire AIES that is currently the primary determinant. The Calgary
area could suffer from voltages straying well outside normal operating limits in the
event certain transmission contingencies occur under high-load conditions. To manage
the potential voltage problems in the Calgary area, the System Controller has access to
the Calpine Energy Centre units under an LBCSO contract.64 In addition, the AESO has
IBOC contracts with the EnCana/Nexen Balzac facility, the EnCana Cavalier facility, and
the TransCanada Energy Carseland facility that provide incentives for these units to
produce energy. (There may be other confidential commercial contracts as well.)
Energy produced in the Calgary region offsets some of the north-to-south flows that can
lead to the voltage stability concerns.
In southeastern Alberta,65 load has increased significantly in recent years. This load
growth has led to some concern about system security following certain singlecontingency transmission outages. Area load must sometimes be constrained if there is
an increased risk to certain transmission elements (e.g., during lightning storms). In fact,
if the McNeil converter station is not available to provide reactive power support to the
area, firm load may have to be curtailed. In addition, some of the load growth has come
in the form of very large motors (up to 54,000 hp), the simultaneous starting of which
could create under-voltage conditions. Consequently, the System Controller must
63
See AESO Operating Policy OPP-501, Northwest Area Operation.
64
See AESO Operating Policy OPP-510, Calgary Area Transmission Must-Run Generation.
65
See AESO Operating Policy OPP-503, Empress Area Operation.
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coordinate the starting of motors larger than 25,000 hp. The future (late 2004)
commissioning of LBCSO generation in the area should help reduce the potential load
curtailment and voltage excursion issues.
TMR is not dispatched to facilitate non-firm exports,66 to supply Demand Opportunity
Service (“DOS”) loads, or to reduce transmission system losses.
8.2 TMR Volumes
As described in the Section 8.1, several factors drive TMR requirements; no one factor
can be isolated as being more important than the others. For example, Figure 8.1 shows
that TMR volumes are not highly correlated with system load, while Figure 8.2 shows
that they are not highly correlated with pool prices, either. (The plausible relationship
between TMR volumes and pool prices is that, as pool prices rise, the higher-priced
generators in areas that require TMR would be more likely to be running from within
the energy market merit order, and less out-of-merit dispatch would be required.)
Figure 8.1: TMR volumes and DTS MWh for 2002.
300
TMR Volume
250
200
150
100
50
0
5000
5500
6000
6500
7000
7500
DTS [MWh]
66
Under the current transmission tariff, all exports are non-firm.
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Figure 8.2: TMR volumes and pool prices for 2002.
300
TMR Volume [MW]
250
200
150
100
50
0
1
10
100
1000
Pool Price [$/MWh] (Log Scale)
8.3 Cost Allocation
8.3.4 Variable TMR Costs
TMR accounts for roughly 75% of the AESO’s voltage control costs. While TMR costs
are theoretically driven by energy prices, the relationship, to the extent it exists, is an
inverse one. Thus, TMR costs are not proportional to energy prices, and are therefore
not particularly amenable to a charge based on energy prices. A change to the current
tariff TMR price, which is a fixed percentage of pool price, is therefore warranted.
No single factor dominates in the determination of the volume of TMR that is required
at any particular time. Thus, no single factor arises from the above analysis as being the
optimal billing determinant for TMR costs. Looking at TMR as a replacement for wires
suggests that costs could be allocated in the same way wire costs are, though the
variability suggests that the allocation be on an hourly basis. Since wire costs are
currently allocated 60% to demand and 40% to energy, it would be reasonable to allocate
60% of each hour’s variable TMR cost based on the customer’s billing capacity and 40%
of each hour’s costs based on the customer’s energy consumption.
An alternative that would likely be easier to administer and would be consistent with
the allocation of most other ancillary service costs is to use a 100% energy allocation.
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The rationale is that the “transmission system” defined by TMR changes every hour,
which implies that an hourly peak (15 minute) demand could be used in place of the
customer’s monthly billing capacity. It is a short step to simply further by assuming that
hourly 15 minute demands will not be too far from the average of all four hourly 15
minute demands; the average is just the hourly energy consumption.
8.3.5 Fixed TMR Costs
Given that TMR may be viewed as a substitute for wires, it is appropriate to allocate
fixed TMR costs on the same basis as wire costs (i.e., 60% demand and 40% energy).
8.3.6 Reactive Power
The majority of the AESO’s reactive power costs are in the form of fixed payments with
respect to the Poplar Hill facility. Given that the costs are fixed, the Board previously
allocated them 100% to demand charges. There is no reason to change this allocation.
8.4 Conclusions
Because there are several factors that determine the requirement for TMR and other
voltage control services, there is no “obvious” billing determinant for those services.
However, because voltage control in general, and TMR in particular, can be viewed as a
substitute for wires, it is reasonable to use the same billing determinants used for wires
costs (i.e., 60% demand and 40% energy). For TMR, a reasonable alternative would be to
allocate costs based solely on energy consumption.
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9 OTHER ANCILLARY SERVICES
The ancillary services not examined above include load shedding, ILRAS, and black
start. Collectively these services account for about 4% of the AESO’s annual ancillary
services expenditures.
9.1 Load Shedding
The AESO procures under-frequency load shedding (“UFLS”) capability under Article 4
and Rate Schedule UFS of the AESO’s tariff. The AESO has the right to require each
demand customer to maintain a minimum of 50% of its aggregate load connected to an
underfrequency load shedding device. Customers receive monthly credits for each kW
of UFS capacity that depend on the frequency setting of the load-shedding relays; these
credits range from $0.035/kW at 58.0 Hz to $0.065/kW at 59.1 Hz.67
The use of UFLS is governed by the AESO’s Operating Policy OPP-804, Off-Nominal
Frequency Load Shedding and Restoration. This policy references the WECC’s Minimum
Operating Reliability Criteria.68
The costs of the AESO’s underfrequency load shedding programs are currently allocated
50% to supply customers and 50% to demand customers. All customer charges are
energy-based, and the price is a specified percentage of pool price. In 2002, had load
customers been responsible for all of the costs, the rate would have been
$5.9 M
= 0.25%.
$45.74 / MWh × 51,058,575 MWh
Loads armed to provide UFLS provide an “insurance policy” to the other loads on the
system. The amount of load protected by that insurance policy is more strongly related
to the load on the system at the time than to the loads’ peak demands. Thus, an energybased cost allocation, as exists under the current tariff, is fair and reasonable. Since the
AESO’s payments are not related to pool prices, a fixed charge per MWh appropriate.
9.2 ILRAS
The Interruptible Load Remedial Action Scheme (“ILRAS”) is an ancillary service that
the AESO procures to enable increased import capability through the Alberta-BC
interconnection. Under the scheme, a certain amount of load is “armed” when the
import level on the interconnection goes above a threshold level. Should the
interconnection trip off when imports are above that threshold, the load is immediately
tripped off.
67
At one time the AESO had a commercial contract with certain load customers to provide UFLS
capability. That arrangement is no longer required.
68
http://www.wecc.biz/documents/policy/WECC_Reliability_Criteria.pdf
Other Ancillary Services
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There are at least two ways of looking at the associated costs. The first (and currently
Board-approved) view of ILRAS is that it is a replacement for wires. Consequently,
ILRAS costs are allocated 60% to demand and 40% to energy under the current tariff,
just as wire costs are. Unlike wire costs, however, ILRAS costs are already allocated
only to load; the reason is that loads benefit from increased imports (and the associated
downward pressure on pool prices), while suppliers do not.
An alternate way of looking at ILRAS is that it replaces contingency (spinning and
supplemental) reserve that the AESO would otherwise have to carry when BC imports
constitute the Alberta control area’s single largest contingency. This view is actually
more consistent with the way the costs are incurred, since the current ILRAS supplier is
paid on a dollars-per-MW-per-minute basis. If ILRAS costs are treated as a substitute
for contingency reserves, then it makes sense to allocate the costs in the same way
contingency reserves costs are allocated (i.e., on an energy-only basis). However, given
that the cost of ILRAS is relatively small, there are no material rate impacts regardless of
how the costs are allocated.
9.3 Black Start
Black start is the necessary but hopefully never-to-be-needed service that allows the
power system to be restarted following a blackout. While the details of the black start
contracts that the AESO has with various suppliers are confidential, the AESO has stated
that the service is generally paid for through fixed monthly payments. The costs for this
service were $1.5 million in 2002, and $2.2 million in 2003.
In the event of a system blackout, transmission customers would presumably be looking
to quickly restore the loads that were on the system immediately prior to the outage.
Consequently, hourly energy rather than monthly or annual peak demand is the
appropriate billing determinant. This is consistent with the way black start costs are
currently allocated.
Other Ancillary Services
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10 CONCLUSIONS AND RECOMMENDATIONS
This report examined the costs incurred by the Alberta Electric System Operator
(“AESO”) to provide ancillary services to ensure the safe, stable, and reliable operation
of the Alberta Interconnected Electric System. A review of the AESO’s costs and the
revenues derived from its tariff leads to the conclusion that the existing rate structure
does not result in a good match between costs and revenues on an hourly basis. It is
recommended that alternative rate designs, which may provide a better match between
costs and revenues while maintaining other import attributes of a sound rate design, be
considered.
The analysis presented above also leads to the conclusion that the billing determinant
currently used for regulating reserve (i.e., energy consumption) is not necessarily the
best one, and that the variability—or range of up-and-down movement—of a load’s
energy consumption may be a better choice. For the other ancillary services the
traditional billing determinants of peak demand and energy are appropriate, though in
certain cases a switch from one to the other may be considered.
Conclusions and Recommendations
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APPENDIX A:
ANALYSIS OF THE MISMATCH BETWEEN OPERATING RESERVE
COSTS AND REVENUES
This appendix contains the analysis that supports the statements made in Section 4.4
about why operating reserve costs and revenues do not match very well. It contains no
“new” results (i.e., results not already stated in the body of the report), but has been
segregated from the body of the report because the analysis is somewhat mathematical.
To obtain a more detailed view of why operating reserve costs and revenues do not
match very well, we can look at the individual components of the OR costs and their
relationship to the revenues generated by a fraction-of-pool-price rate. The components
of the OR cost are the payments made to active providers, the premiums paid to standby
providers, the activation payments made for activated reserves, and the payments made
to suppliers under non-AS-exchange contracts.
The active OR cost in an hour, CA, is given by
(A.1)
C A = ∑ q Ai max( P + X i ,0) = Q A ( P + X ) ,
i
where qAi is the quantity (in MW·hr) under active OR contract i, P is the hourly pool
price, Xi is the index price associated with contract i, QA is the total active OR quantity in
the hour, and X is the volume-weighted average index price for the hour. Normally, Xi
is negative, which means that the supplier’s price for OR is below pool price. In theory,
Xi represents the savings in fuel and variable O&M expenses that a supplier realizes
because the unit providing OR will (of necessity) operate at less than full output.
The standby OR cost in an hour is
(A.2)
C S = ∑ qSj p j = QS p ,
j
where qSj is the OR quantity under contract j, pj is the associated premium, QS is the total
quantity of standby OR, and p is the average premium. Similarly, the activated standby
cost in an hour is
(A.3)
C AS = ∑ q ASk a k = Q AS a ,
k
where qASk is the OR quantity under activated contract k, ak is the associated premium,
QAS is the total quantity of activated standby OR, and a is the average activation price.
If CNX is the cost associated with non-exchange-based contracts, then the total OR cost in
an hour is
Data
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(A.4)
CT = C A + C S + C AS + C NX = Q A P + Q A X + Q S p + Q AS a + C NX .
(Note that X ≥ − P since the price paid to suppliers for active OR does not go below zero.
Also, recall that the averages in this equation are hourly averages, i.e., averages across all
of the OR contracts applicable in that hour.)
The hourly revenues are equal to
(A.5)
RT = rEP ,
where r is the rate for OR, E is the DTS energy consumption, and P is the pool price.
An examination of the individual terms in Equation (A.4), and the relationship between
Equations (A.4) and (A.5), can provide some insights into why it is unlikely that OR
costs will match the OR-related revenues generated by a fraction-of-pool-price rate.
Consider the very simplest (hypothetical) case in which the AESO purchases only active
OR and the index price is zero. In this case, the only term in Equation (A.4) is the first,
so that the revenue/cost ratio is
(A.6)
ρ=
RT
E
rEP
.
=
=r
QA
CT Q A P
(ρ is the Greek letter “rho”). The two terms on the right side of this simple equation each
provide a reason why costs and revenues may not match. The first term, r, is calculated
by the AESO at the time it makes its forecasts of costs and revenues for the applicable
tariff test period. Its influence on values of ρ different from 1 is therefore through
forecast error. As noted above, forecasting OR costs is extremely difficult because of
their volatility.
The next factor on the right side of Equation (A.6) is the ratio (E/QA), which is the ratio
of AIES MWh to OR MW·hr. In most hours, the volume of contingency reserve that is
on line is directly related to E through the “five-and-seven” rule.69 However, the hourly
AGC volume—which is typically about 25% of the OR total—does not increase and
decrease in proportion to E. Consequently, QA fluctuates less than E. Therefore, E/QA
tends to decrease in off-peak hours and increase in on-peak hours (see Figure A.1),
which implies that revenues are below costs (ρ < 1) during off-peak hours and above
costs (ρ > 1) in on-peak hours. In addition, the AESO procures the bulk of its OR
through the ancillary services market, and may be purchasing up to five days ahead of
an operating hour. As a result, load forecast errors contribute to variations in E/QA, and
therefore to ρ’s deviations from 1.
69
Under WECC rules, the volume of contingency reserves a control area must carry is (roughly) five
percent of firm load served by hydro generation plus seven percent of the firm load served by thermal
generation. This rule will be discussed further in Section 9.
Data
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If the assumption that the index price for active OR in each hour is zero is abandoned,
then the next term ( Q A X ) in Equation (A.4) becomes non-zero. As Figures A.2 and A.3
show, the market-determined values of X have a wide range, exhibit significant
volatility, and are distributed differently during on-peak and off-peak hours. The
distributions differ because, as noted above, the X values represent reduced fuel and
variable O&M costs realized by OR suppliers. As more-expensive units come on line
during on-peak hours, the savings per MW·hr increase, the discounts from pool price
get larger, and the X values become more negative. (Note that the more-expensive units
do not necessarily become the OR providers during on-peak hours, but their largerdiscount offers will tend to cause the discounts offered by other providers to get larger.)
Figure A.1: The ratio of DTS MWh to OR MW·hr during a week in October, 2002.
11.5
7000.0
Load-to-OR Ratio (E/QA)
Load (E)
11
6000.0
10.5
5000.0
10
4000.0
9.5
3000.0
E/QA
9
2000.0
8.5
1000.0
8
0.0
15
16
17
18
19
20
21
Day (October, 2002)
When the standby OR purchases are added, the revenue/cost ratio becomes
(A.7)
ρ=
rEP
.
Q A ( P + X ) + QS p
The new term ( Q S p ) brings in yet more opportunities for ρ to deviate from the ideal
value of 1. The AESO procures sufficient standby reserves to cover errors in its OR
volume forecasts and the possibility that one or more active OR providers may be
unable to deliver reserves when called on by the System Controller. The volume of such
purchases is relatively stable, but like the active OR index prices, the standby premiums
Data
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can vary widely (see Figures A.4 and A.5). The premiums are established by suppliers
offering into the AS market and are not necessarily related to pool prices.
The final AS-market-derived factor in the revenue/cost ratio ( Q AS a ) is that related to
standby reserves, which are activated by the System Controller in response to shortages
of active reserves resulting from forecast errors or the inability of active OR providers to
deliver. Including this term makes the revenue/cost ratio
(A.8)
ρ=
rEP
rEP
=
,
Q A ( P + X ) + QS p + Q AS a Q A ( P + X ) + C
where C is the total cost of non-active OR for the hour.
Obviously, the volume of reserves that must be dispatched in any hour (QAS) is
unpredictable. Adding to that unpredictability is the fact that a , the hourly activation
price, is quite volatile (see FigureA.6).
Even if the hourly costs and volumes of standby OR and activated standby OR were
stable, ρ would still exhibit some large deviations from 1. As the discount offered by
active OR suppliers approaches the pool price, the cost of active OR decreases; in fact,
during 2002 there were hundreds of hours in which the price dropped to zero.70 If no
activation of standby reserves is required, C is also relatively small, and ρ gets very
large. Similarly, if standby reserves must be activated at low pool prices, C may be large
when rEP is small, leading to values of ρ much less than 1 (i.e., significant underrecovery of the hourly cost). During 2002, there were more than 100 hours in which
revenues were less than 25% of the costs, and there were over 200 hours in which
revenues were more than 400% of costs (see Figure 4.4).
These results of the analysis given in this appendix were summarized in Section 4.
70
There were no hours in which the total cost of operating reserves dropped to zero.
Data
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Figure A.2: Active OR index prices for the second half of October, 2002.
0
-10
Index Price [$/MW-hr]
-20
-30
-40
-50
-60
-70
-80
-90
-100
15
16
17
18
19
20
21
22
23
24
25
26
27
27
28
29
30
31
Date (October, 2002)
Figure A.3: The distribution of active OR index prices for 2002.
0.06
Relative Frequency
0.05
Off Peak Hours
0.04
On Peak Hours
0.03
0.02
0.01
0.00
-80
-70
-60
-50
-40
-30
-20
-10
0
10
Active OR Index Price [$/MW-hr]
Data
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Figure A.4: The hourly average standby OR premiums for a period in 2002.
Standby OR Premium [$/MWhx]
4.80
4.60
4.40
4.20
4.00
3.80
3.60
3.40
3.20
3.00
6
7
8
9
10
11
12
13
14
15
16
17
18
19
Day (October, 2002)
Figure A.5: The distribution of the hourly average standby OR premiums for 2002.
0.45
0.4
Relative Frequency
0.35
0.3
0.25
0.2
0.15
0.1
0.05
0
2
3
4
5
6
7
8
9
10
11
Active OR Premium [$/MW-hr]
Data
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Figure A.6: The distribution of hourly average activation prices in 2002.
0.012
Relative Frequency
0.01
0.008
0.006
0.004
0.002
0
0
50
100
150
200
250
300
350
Activation Price [$/MW-hr]
Data
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APPENDIX B: DATA
The results in this study were based on analyses of the following data.
Ancillary Services Market Transactions
The AESO made available data on each individual transaction that took place through
the Watt-Ex exchange over the course of 2002. Active reserve transactions, standby
reserve transactions, and standby reserve activations were all included. The transaction
data was aggregated to derive an hourly cost for each of the exchange-traded ancillary
services (regulating reserve, spinning reserve, and supplemental reserve). The hourly
data was aggregated on a monthly basis and compared to accounting data in order to
check its reasonableness (see Figure B.1). No attempt was made to perform a detailed
reconciliation because the AESO’s ancillary service costs include amounts for services
not purchased through the exchange.
Figure B.1: Calculated and reported ancillary service costs for 2002.
25
Cost [M$]
20
15
10
5
0
1
2
3
4
5
6
7
8
9
10
11
12
Month
Calculated
Reported by AESO
One-Minute Customer Data
One-minute telemetry data was provided by the AESO for a number of load, dual use,
and generation customers. The data covered two one-week periods in 2001, two oneweek periods in 2002, and two-day and one-day periods in 2002. One-minute data on
AIES load was also provided.
Data
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Transmission Must-Run Data
Hourly data covering approximately 75% of the AESO’s 2002 transmission must-run
costs was provided by the AESO. This data was used in the analysis of the match
between hourly costs and hourly revenues.
System Data
The AESO provided system data measured at one-minute intervals for all but a few days
in 2003. The data included system load, system frequency, area control error, regulation
up, regulation down, and scheduled and actual imports and exports. The data were
used to establish hourly “actual” regulation and contingency reserve volumes, which
were used primarily to examine the relationship between reserve volumes and the
associated billing determinants. No attempt was made to reconcile volumes determined
in this way with purchases in the ancillary services market because it is entirely
reasonable to expect material differences between purchased volumes and the volumes
actually used in real time.
Billing Quantities
The AESO provided hourly values for energy consumption by DTS customers for 2002,
as well as monthly DTS consumption data for 2003. These values were used in the
calculation of ancillary service costs per DTS MWh, and in the estimation of the revenue
that would have been derived through the AESO’s tariff had all costs been charged to
DTS customers.
Market Data
Publicly available market data, primarily hourly pool price values, was also used in the
analysis. Pool price data was used to estimate hourly tariff revenues for comparison to
hourly costs.
Data
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