CAISO Public
__________________________________________
Summary of
October 2010 Stakeholder Comments
and ISO Responses on
Intermittent Dynamic Transfer Capability Study
Provided in Support of 2009-2010 Stakeholder Process to Consider
Expansion of Dynamic Transfer Services in ISO Tariff
November 12, 2010
CAISO/MAD/JEP
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Summary of October 2010 Stakeholder Comments and ISO Responses
on Intermittent Dynamic Transfer Capability Study
Stakeholder
Comment
ISO Response
IID
IID strongly supports dynamic transfers.
IID urges that the study will be conducted
in a way that promotes accuracy and
transparency, while maintaining a degree
of urgency. It is IID’s view that the best
way to achieve these objectives is to also
lean on the additional expertise readily
available from neighboring BAs that share
the CAISO’s interest in facilitating and
promoting dynamic transfer. Indeed, the
Dynamic Scheduling System or “DSS”
underscores the high priority of the issue
WECC-wide.
To ensure the involvement of
neighboring balancing
authorities, the ISO is contacting
individual neighboring BAs, has
presented briefings to WECC’s
Seams Issues Subcommittee
and Variable Generation
Subcommittee, and is
participating in a Dynamic
Transfer Capability Task Force
that is examining the Pacific
Northwest region, in addition to
conducting stakeholder
conference calls in the ISO’s
dynamic transfers stakeholder
process. The stakeholder
conference calls review the
structure of the ISO’s base case
and study assumptions as they
are developed during the study
process. The ISO is also
examining how it can integrate
DSS with its market systems.
Provide additional opportunities for review
and input from stakeholders in the
adoption of its base case and study
assumptions prior to proceeding with the
dynamic transfers study; and make it a
priority to contact and confer with
neighboring BAs with direct interests’ in
the initial paths being studied (i.e., COI
and WOR).
LS Power
The CAISO should share the base cases
and study assumptions with the
stakeholders, particularly the RPS level
modeled for study (20% or 33%), the
generation mix (renewable vs. fossil fuel)
within and outside California, load level,
whether local capacity requirements are
met with generation dispatched, and what
new transmission projects will be
assumed in service.
Some sensitivity studies should be done
prior to establishing any limits, to help
answer questions such as any difference
in limits if a dynamic transfer is from a
variable generation resource vs. a fossil
fuel resource (for instance, any difference
when DV/DP test is done and generation
CAISO/MAD/JEP
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The base case for this study is
the WECC 2018 heavy spring
case, which is available on
WECC’s web site to authorized
users. The WECC base case
establishes the basic
transmission topology,
generation mix, and load level.
Attachment 2 to these
responses to stakeholder
comments describes the
modifications that the ISO has
made to the WECC base case.
This study is not intended to be
an evaluation of whether the
base case meets local
generation requirements within
the ISO, which are the subject of
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PG&E
is tripped outside California to monitor the
impact of voltage drop, if the generation
tripped outside California is a variable or
fossil fuel resource), and sensitivity with
load level.
other ISO studies.
The CAISO needs to clarify the role this
study will play in determining the actual
level of intertie capacity set aside for
dynamic transfers. As proposed, it
appears this study will only address the
operating limits on transfers from a
system reliability and stability perspective.
The study should provide a maximum
amount of each intertie that could be
devoted to dynamic transfers without
harming reliability. However, there are
other considerations that should be taken
into account in determining how much
intertie capacity will be set aside for
dynamic transfers. These include such
considerations as market price impacts.
This study addresses the
dynamic transfer capability for
intermittent resources, which is
a system reliability and stability
issue. Other areas of the ISO’s
proposals for dynamic transfers
address mechanisms for
maintaining transmission
utilization as high as possible,
recognizing that dynamic
transfers of intermittent
resources will often not use their
full amount of transmission that
is reserved in a particular hour.
In particular, the ISO’s proposals
will allow dispatchable dynamic
transfers to exceed their own
transmission reservations
through the use of recallable
transmission, which the ISO will
award for 5-minute intervals
through real-time dispatch, when
other dynamic transfers are not
fully using their reserved
capacity in real-time. An
example following this table
(Attachment 1) of comments and
responses illustrates the results
of scheduling and dispatching
intermittent and dispatchable
dynamic resources in greater
detail, and suggests that in
practice, the impact of dynamic
transfers’ transmission
The CAISO needs to take account of the
market impacts of reducing the intertie
capacity. PG&E suggests the CAISO
include economic considerations in this
study or address these issues in a
separate study. Intermittent schedules
will need to reserve transmission capacity
for their maximum expected output in any
given hour. Because it is unlikely an
intermittent resource will produce
consistently at the reserved maximum,
some transmission capability will be left
unused.
Two aspects of the proposed reliability
study to be unrealistic. The algorithm to
select generators for redispatch when
imports decrease should be adjusted. As
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Once this study of intermittent
dynamic transfer capability is
complete, the ISO will schedule
stakeholder meetings to explore
how any limitations on transfer
capability would translate to
limitations on enrollment or
scheduling of dynamic transfers
of intermittent resources. The
ISO plans on doing a sensitivity
study with a WECC 2020 heavy
summer base case.
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Powerex
the study is currently structured, a
decrease in renewable imports over the
interties will result in the redispatching of
internal resources on a pro rata basis,
resulting in several hundred small
incremental dispatches that will have little
or no effect on the Delta V/Delta P ratio.
In reality, a small number of resources will
be significantly dispatched, with much
greater impact on the local voltages
where these resources are located, and
could push the system farther down to the
point of voltage collapse, as a large
movement in one generator would cause
a need for more local VAR support.
Second, the CAISO should model
intermittent resources on a time interval
less than ten minutes to better reflect
variability. Given this improper modeling
of the system, it is unlikely that the results
will conclude that intermittent dynamic
transfers could cause problems.
reservations that remain unused
in real-time would be limited.
Powerex would appreciate additional
explanatory information so that the data
presented on ramps can be better
understood. For example, what caused
the 600+ MW maximum up ramps and
400 MW down ramps in July 2010 or the
wind 10-minute up and down ramps that
appear to exceed 200 MW?
The upward and downward
ramps in the first interval for
WOR and COI are part of the yaxis and not representative of
actual ramps. Other large
ramps were primarily due to
hourly scheduled ramp changes
on the ties. The 10-minute wind
ramps in excess of 200 MW
were due to bad data.
The CAISO should expand Task 1,
Voltage Performance, where one
objective is to “Identify any resulting
impact on equipment”, to identify if this
also requires additional manual
intervention or increase in workload for
operators and/or arming/disarming or
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For changes in renewable
imports, only dispatchable
resources in the base case are
re-dispatched. As suggested,
the ISO would also look at
additional sensitivities whereby
only a small subset (about 10) of
resources post contingency
would be dispatched.
10-minute variability was chosen
for the following two reasons:
(1) out-of-state solar and wind
data were in 10-minute timesteps, and (2) the ISO market
timeline from when the decision
is made to move a resource to a
new operating point until the
resource reaches the new
operating point is about 10minutes. For steady state power
flow analysis, the CAISO does
not believe that modeling of
intermittent resources on a time
interval less than 10 minutes
provides benefit since 10-minute
variability would be greater than
the variability for any timeframe
less than 10-minutes.
The ISO is participating in the
recently-formed Dynamic
Transfer Capability Task Force
that is examining the Pacific
Northwest region.
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creation of Remedial Action Schemes.
Powerex is especially interested in Task
2, Oscillatory Performance, since this may
be the first study of this feature
undertaken in the PNW.
Dynamic transfer capability studies are
being performed in the PNW. The CAISO
should work with these other
organizations through technical
workshops or coordination of study
assumptions
SCE
Current OTC limits are a reasonable
starting point to consider the capability to
accommodate dynamic schedules. Today
the CAISO can manage dramatic
variations in flow on the ties over the
normal ramps (from maximum rated
outflow to maximum rated inflow);
therefore it would follow that the CAISO
can accommodate this same level of
change throughout the hour. The CAISO
should clarify what additional information
it expects to obtain regarding OTC limits.
Studying COI and WOR separately is an
over simplification that will mask potential
impacts of dynamic transfers. A study of
the entire CAISO grid is needed to
determine the impact of N-1/N-2 resource
losses. The limited proposed
methodology may not be applicable to the
rest of the interties.
The ramping and regulation availability to
compensate for dynamic transfers should
be made unlimited, to prevent any preset
resource limitations from imposing an
artificial restriction on dynamic transfers.
It appears that the study could result in a
change to current OTC limits. Will this
study consider the current method of
calculating OTC limits at the ties by
revisiting that calculation and its
underlying logic? Will the study look at
the relationship between the OTC limits
and dynamic transfer limits? For
example, will the study consider whether
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The ISO manages large hourly
ramps because these ramps are
scheduled and are coordinated
between the affected balancing
authorities. The ISO is
concerned with large intra hour
swings due to the intermittency
associated with variable
generation.
These studies are not intended
to change the current OTC limits
but establish a dynamic transfer
limit within the current OTC limit.
All studies are done with WECC
base cases, however COI and
WOR were not loaded to their
maximum OTC limits in the
same base case. Thus, the
flows on all ties were impacted
post contingency.
The ISO’s study focuses on
identifying any limitations on its
capability to support dynamic
transfers of intermittent
resources, and the ISO does not
intend this study to lead to an
overall evaluation of the OTC
across its interties. The ISO has
examined whether an analysis
of simultaneous high flows on
COI and WOR would be
meaningful, and concluded that
the assumptions needed to
produce this condition would not
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be realistic. The ISO’s study
assumes that adequate ramping
and regulation capacity is
available from generation within
SCE would like to clarify the basis of
the ISO to balance the variation
WOR capacity and how it will be used.
of intermittent dynamic transfers,
Since CAISO shares that capacity with
and is then examining the
others we would like to assure that it is
appropriate for the work to be undertaken. impacts of variations in power
flowing on the transmission
What steps are being taken to include
system.
other entities in the study since their
transmission standards will also impact
If the ISO determines that
grid operation? The WOR rating used in
intermittent dynamic transfers
this study should be consistent with OTC
across WOR are subject to
studies and appropriately reflect the
limitations within the ISO grid,
transmission rights of non-CAISO entities. the ISO will coordinate with its
neighboring BAs to evaluate the
SCE sees the need for additional
impacts of such limitations. The
iterations during the development of this
ISO does not assume that it
methodology.
would be able to schedule
transmission capacity that has
not been placed under ISO
control. Once the results of this
study are available, the ISO will
evaluate whether additional
studies are needed.
OTC limits at all BA ties may change
under dynamic transfer if COI and WOR
have simultaneous high flows?
SMUD
To ensure the involvement of
neighboring BAs, the ISO is
contacting individual neighboring
BAs, has presented briefings to
WECC’s Seams Issues
Subcommittee and Variable
Generation Subcommittee, and
is participating in a Dynamic
The study objectives/methodology has not
Transfer Capability Task Force
identified the study criteria to be met or
that is examining the Pacific
how to arrive at the dynamic transfer
Northwest region, in addition to
limits. This should include the proper
conducting stakeholder
assumptions regarding dynamic transfer
conference calls in the ISO’s
limits (de-rates) when the transmission
dynamic transfer stakeholder
paths are limited below their path ratings.
process. The stakeholder
It is essential to choose the correct base
conference calls review the
cases, such as recent WECC OTC study
cases. The current choice of a 2018 case ISO’s study plan and
should also be used, but as a sensitivity in assumptions as they are
developed during the study
the planning horizon. A benchmarking
process.
case of the current system conditions will
The ISO is evaluating additional
also be useful and therefore should be
In order to make this study most
productive, a clear and transparent study
plan should be provided to stakeholders
and additional input be allowed at the
front end of the process. Additionally, the
CAISO needs to engage neighboring
balancing authorities as soon as possible.
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created.
The CAISO should include the
assessment of impacts on COI
curtailment on both the CAISO
transmission users and the non-CAISOcontrolled grid users (i.e., owners of
COTP within the SMUD BA). The
dynamic transfers program must assure
that the non-CAISO owners of COI rights
are not adversely impacted. If the CAISO
and non-CAISO users are to be exposed
to greater curtailment risk or economic
mitigation obligations this should be
identified and quantified in the study.
outages in its power flow
analyses, to consider the impact
of critical outages on the COI
and WOR interfaces in the
steady state analysis in addition
to the original approach of
evaluating generation changes
to emulate a change in wind or
solar plant output. The 2018
power flow case is being used
as the most recent WECC base
case that reflects the high level
of renewable energy that may
present reliability issues. The
ISO is also planning to run
sensitivities with a WECC 2020
heavy summer base case.
If the ISO determines that
intermittent dynamic transfers
across COI are subject to
limitations within the ISO grid,
the ISO will coordinate with its
neighboring BAs to evaluate the
impacts of such limitations. The
ISO does not assume that it
would be able to schedule
transmission capacity that has
not been placed under ISO
control.
8minutenergy In general, we have no problems with the
basic study methodology. Instead, our
comments (and concerns) focus on the
way in which the results will be used. The
studies will be a reasonable tool to: (1)
identify many of the potentially
troublesome aspects of intermittent DT on
the major transmission paths; and (2)
indicate a general approach that could be
used on other interties as well. However,
the methodology and results for these
interties should not be applied to other
interties or other conditions, without
further examination.
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Once this study of intermittent
dynamic transfer capability is
complete, the ISO will schedule
stakeholder meetings to explore
how any limitations on transfer
capability would translate to
limitations on enrollment or
scheduling of dynamic transfers
of intermittent resources. At that
time, the ISO may also identify
needs for further studies such as
applicability to other interties or
other operating conditions.
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Attachment 1:
Example for Analysis of Market Impacts of Transmission Reservations for
Intermittent Dynamic Transfers
A question that has arisen during stakeholder discussions is whether the ISO should impose
limits on how much intertie capacity will be allowed to be scheduled by dynamically
transferred resources, particularly by intermittent resources. The concern is that there may
be market price impacts of transmission capacity being reserved in day-ahead or hour-ahead
timeframes, but then not used in real-time. This illustrative analysis explores whether
significant market impacts are likely to occur, and thus whether the ISO should conduct a
more extensive study of these economic considerations. In considering the results of this
illustration, it will be necessary to consider the full package of proposals resulting from this
stakeholder process, which includes mechanisms for maintaining transmission utilization as
high as possible, recognizing that dynamic transfers of intermittent resources will often not
use their full amount of transmission that is reserved in a particular hour. Intermittent
resources that schedule using dynamic transfers may choose to reserve transmission
capacity beyond their pre-scheduled energy delivery, to gain assurance of delivering their
maximum expected output in any given hour, but the ISO’s proposals do not require such
additional transmission reservations. The actual extent of transmission reservations
exceeding pre-scheduled energy will depend on market participants’ risk assessments
between the cost of additional transmission reservations and the availability of transmission
by 5-minute interval within the operating hours. Because of variations in intermittent
resources’ delivery, some reserved transmission capability will be left unused in some
intervals, but when other dispatchable dynamic resources are available at the intertie, the
ISO will dispatch these resources in the affected intervals through the use of recallable
transmission.
This illustrative analysis performs production cost simulation runs using new intermittent
resources scheduling at the Palo Verde, Four Corners, and Mead interties to examine the
potential for market impacts of dynamic transfers of intermittent resources.1 The starting
point for this analysis is the market model used by the ISO’s Department of Market
Monitoring (DMM) for its Fall 2010 competitive path assessment, using PLEXOS software.2
To represent the most typical conditions, the simulation presented here uses DMM’s medium
load and medium hydro scenarios, modified substantively only in the modeling of dynamic
schedules. 3 The analysis adds new dynamic transfers using hourly profiles from the WECC
1
2
3
This analysis focuses on renewable imports from the southwestern states due to limitations that BPA has documented in its ability
to support additional dynamic transfers across COI. The ISO believes that it will be able to adapt its dynamic scheduling
functionality with the intra-hour scheduling functionality that some balancing authorities including BPA are developing, in order to
support new resources, but details of such approaches are beyond the scope of this analysis.
DMM’s Competitive Part Assessment for Fall 2010 is available at http://www.caiso.com/2829/2829dbd157e30.pdf. Additional detail
of its methodology is available in the Competitive Path Assessment for MRTU Final Results for MRTU Go-Live, at
http://www.caiso.com/2365/23659ca314f0.pdf.
The cases described herein maintain DMM’s treatment of self-scheduled resources being bid at $0/MWh for existing resources in
DMM’s model. New renewable generation that would be dynamically transferred is modeled using a bid price of $-30/MWh to
determine the impact of such generation on the scheduling of other intertie resources, and for consistency with the value of the
renewable resources’ renewable energy credits and tax credits. As an estimate of future market activity, this analysis uses the
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Transmission Expansion Planning Policy Committee (TEPPC), assuming that 50% of future
additions of wind and solar generation in Arizona, southern Nevada, and New Mexico would
be dynamically scheduled into the ISO’s market. To utilize existing ISO scheduling points,
solar generation additions from Arizona and New Mexico are modeled at Palo Verde, wind
additions from these states are modeled at Four Corners, and solar additions in southern
Nevada are modeled at Mead. Specific details for five modeled cases are as follows:
Case 1 – Reference case (internal intermittent resources): As a point of reference to isolate
the impacts of dynamic transfers on intertie scheduling from impacts from simply having new
generation in the ISO market, the added dynamically transferred wind and solar generation is
placed within the ISO area rather than in other states, as an addition to the DMM competitive
path assessment market case.4
Case 2 – Addition of dynamic transfers of renewable resources, without allowing transmission
reservations: As noted above, using hourly profiles from TEPPC data, 50% of the future
additions of wind and solar generation in Arizona, southern Nevada, and New Mexico are
assumed to bid into the ISO market at Palo Verde, Four Corners, and Mead (50% of 2970
MW of new wind and 4300 MW of new solar, for a total of 3635 MW of added capacity in the
ISO market), at a bid price of $-30/MWh, with no added transmission. This case establishes
an additional benchmark for comparison with cases 3 to 5, by showing the impact of adding
these low cost MWh without other market design features.
Case 3 – Allowance for dynamically transferred resources to submit bids for transmission
capacity reservations beyond their energy schedules: The ISO’s proposal to allow
transmission reservations to accommodate variations in dynamic resources’ output allows
economic bids for such capacity, but not self-schedules. Transmission reservations apply in
pre-scheduling timeframes (DAM and HASP), but not to routine dispatch within operating
hours. The assumed MW bid for transmission reservations is the median of one standard
deviations of generation output within hourly periods (23.4% of the hourly average generation
outputs), for 5-minute profiles of New Mexico wind generation, using Western Wind and Solar
Integration Study (WWSIS) data. To distinguish these transmission capacity reservation bids
from self-scheduled imports (priced at $0 in DMM’s data set), the assumed bid price is
$1/MWh.5 This results in higher reservations of intertie transmission capacity, as discussed
further in the discussion below.
4
5
average bid MW and prices for other dynamic transfers from combined days in DMM’s data set for medium load and hydro, when
non-zero MW amounts were bid.
Because this analysis does not add transmission capacity within the ISO that will be necessary to support internal additions of
renewable generation, the in-state resource locations are placed at 500 kV buses, and the results were reviewed to verify that new
congestion had not been created by the added generation. New wind generation is placed 90% in the SCE area (60% of this being
at Vincent substation and 40% at Devers substation), and 10% in the PG&E area (60% of this being at Tesla substation and 40% at
Vaca-Dixon substation). New solar generation is placed 80% in the SCE area (50% of this being at Lugo substation and 50% at
Devers substation), and 20% in the PG&E area (50% of this being at Gates substation and 50% at Midway substation).
Bid prices in this analysis reflect relative scheduling characteristics: renewable resources may be likely to continue self-scheduling
despite negative LMPs due to renewable energy credits and tax credits, so renewable resources have a $-30/MWh bid price. This
analysis maintains DMM’s modeling of energy self-schedules with a $0/MWh bid price. In the ISO’s proposals for refinement of
dynamic transfer policies, transmission reservation bids are only for transmission capacity that is in addition to energy schedules
and must be bids, not self-schedules. Pricing transmission reservation bids at $1/MWh while existing self-scheduled imports have a
$0/MWh bid price ensures that the self-schedules for energy will take precedence over the economic bids for transmission
reservations, while assuming that the transmission reservation bids place a higher value for transmission capacity than economic
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Case 4 – Real-time dispatch, with hourly intertie schedules fixed at prescheduled amounts
from Case 3: This case represents a real-time dispatch scenario, in which hourly intertie
schedules are limited to the pre-scheduled amounts determined in Case 3. Dynamic transfer
schedules within operating hours are not limited by the transmission reservations that could
limit hourly intertie schedules following Case 3, based on the ISO’s overall package of
proposals for refinement of dynamic transfer policies.
Case 5 – Added dynamic transfers of dispatchable resources: A significant part of the ISO’s
proposals for dynamic transfers is allowing economic bids for dispatchable resources to be
dispatched above the pre-scheduled transmission reservations, as “recallable” transmission
that is firm for 5-minute intervals, but not scheduled beyond the timeframe of successive 5minute intervals. To illustrate the increase in transmission utilization that this mechanism
allows, 500 MW of bids for dispatchable resources are added at Palo Verde, priced at 99% of
the SCE LAP price from Case 2.6 The increased utilization of intertie capacity is shown in
Figure 2. The 500 MW of added dynamic transfer is fully dispatched in 28 hours out of a total
of modeled hours (four seasons each represented by a typical day of 24 hours), not
dispatched at all in 20 hours due to congestion, and partly dispatched in 48 of the 96
modeled hours, in which the added dynamic transfer is a marginal bid. (Of these 48 hours
when the added dynamic transfer is a marginal bid, the total schedule at Palo Verde reaches
its limit in 16 hours, and the Palo Verde intertie remains uncongested in the other hours, with
this bid being marginal for a larger part of the ISO market.)
Figures 1 to 4 show results of these cases for four seasonal (calendar quarters) data sets
that comprise the DMM market simulation data. The selection of dates that represent each
season is described in DMM’s reports on its competitive path assessment.
Figure 1 compares the hourly LMPs for the ISO’s three major load aggregation points (LAPs),
for cases 1, 2, and 4. The data points for the three LAPs are indistinguishable in most hours
due to limited congestion of enforced constraints within the ISO area.7 Similarly, the results
for cases 2 and 4 are indistinguishable in most hours of this graph, which reflects the
observations stated below that transmission reservations do not appear to have significant
impacts on market outcomes. The distinction that is visible in Figure 1 is between case 1, in
which renewable resource additions are within the ISO, versus cases 2 and 4, in which the
additional renewable resources are dynamically transferred into the ISO. This difference in
prices results from limits on the additional renewable resources’ ability to get into the ISO
market within the existing intertie capacity, and additional impacts on prices due to allowing
dynamic transfers to reserve intertie capacity do not appear significant.
6
7
energy bids, whose potential displacement is the subject of this analysis. Treating the transmission reservation bids as low-priced
energy bids reduces the meaning of energy prices in case 3, but is necessary since the PLEXOS software does not currently
provide for transmission capacity reservations that are separate from energy schedules.
The bid quantity of 500 MW is intended as a conservative estimate of new dispatchable dynamic transfers. Since the timeframe of
the data is DMM’s data set, Gila River has become operational as a dynamic schedule at Palo Verde, and the ISO has had
additional inquiries about dynamic transfers including conventional resources.
In DMM’s competitive path assessment, market participant portfolios are removed from participation in the market, which results in
more congestion than in this base case. In the daily running of ISO markets, outage conditions lead to congestion that is not
reflected in this base case.
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Figure 2 presents the study results for utilization of the Palo Verde intertie, and indicates that
the addition of low cost resources that would compete for the existing intertie capacity would
produce congestion at the Palo Verde scheduling limit in a number of hours. This appears as
the difference between the solid line representing case 1 and the dashed line representing
case 2. The dotted line representing case 3 shows the combined intertie utilization with
energy schedules summed with additional transmission reservations for intermittent
resources, and the solid markers representing case 4 shows the final real-time transmission
utilization after accounting for hourly schedules being limited from further scheduling in realtime after dynamic transfers bid to reserve extra transmission capacity prior to real-time.
Notably, the final transmission utilization in case 4 is indistinguishable in most hours from the
results of case 2, which did not allow for the extra transmission reservations. Given the
historical bid data collected for DMM’s competitive path analysis, little capacity is affected in
case 4 by case 3’s reservations of transmission capacity, because the energy bids of hourly
intertie resources are either competitive in all cases, or not competitive in any of the cases.
Reductions in real-time intertie schedules at Palo Verde occur in 10 of the 96 simulated
hours, but the maximum reduction is 0.02 MW. Thus, any reduction in scheduled imports
from non-intermittent sources is due to the introduction of low priced MWh from intermittent
resources, not from allowing transmission reservations exceeding energy schedules.8
Reductions in real-time transmission utilization, due to transmission capacity reservations by
dynamic transfers, would be limited to instances in which self-scheduled energy (including
that of intermittent resources) does not fully utilize an intertie’s capacity, hourly energy bids
are available at prices that would be economic in the market, but transmission reservation
bids express a higher value for the transmission capacity. The higher value of such
transmission reservation bids would represent market participants’ risk assessments of their
needs to deliver energy in real-time at MW levels exceeding their expected average delivery,
rather than requirements in the ISO market to reserve their maximum capacity, because the
ISO will allow deliveries exceeding transmission reservations using recallable transmission
for 5-minute intervals within operating hours.9
Figures 3 and 4 show the results of cases 1 to 4 for Four Corners and Mead, respectively.
These results are similar to those for Palo Verde. At Four Corners, reductions in real-time
transmission utilization occur in three hours, with reductions in case 4 relative to case 2 of
0.01, 78.9, and 125.1 MW. At Mead, a reduction in real-time transmission utilization occurs
in one hour, with a reduction in case 4 relative to case 2 of 25 MW.
The following table shows details for the simulated hour with the highest transmission
reservation beyond energy schedules, at Palo Verde, to demonstrate the observations
presented through Figures 2 to 4. Static import and export schedules are the same in all
cases. Additional energy bids are available, but are priced above the LMP in each case.
New dynamically transferred solar generation is scheduled in cases 2 to 5. In case 3, the
8
9
The result of case 5 is also shown in Figure 2, and is discussed in the description of case 5 (addition of dispatchable dynamic
resources) in order to show the mitigation that can occur if case 4 had shown meaningful reductions in intertie utilization. Because
significant reductions in intertie utilization are also not present in the results for Four Corners or Mead, Figures 3 and 4 do not
include case 5.
Dynamic transfers may face limitations by other balancing authorities to limit deliveries to their transmission reservations up to the
ISO’s scheduling point. However, this limitation may vary between balancing authorities, and balancing authorities may have more
transmission capacity for market participants to get to the ISO’s scheduling points than the ISO is able to schedule across the
corresponding intertie.
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additional transmission reservation bid for the new solar generation can also be scheduled.
The impact of limited intertie capacity is not seen until scheduling of additional dispatchable
dynamic transfers is considered in case 5.
Season 3, Hour Beginning 08:00: Uncongested in Case 3
Case
Static import Static export New Solar Solar Transmission
schedules
schedules
Reservation
1: Reference case
2093
811
2: Add intermittent DT
2093
811
1574.2
3: Add transmission reservations 2093
811
1574.2
368.4 (equal to bid)
4: RT dispatch after reservations 2093
811
1574.2
5: Add new dispatchable DT
2093
811
1574.2
New
Dispatchable DT
471.8
Figure 5 provides additional insights indicating that allowing transmission reservations
beyond expected energy delivery for dynamic transfers may not significantly impact other
transmission usage, by providing duration curves for available transmission capability (ATC),
scheduled capacity, and remaining unscheduled capacity at Palo Verde, for the April to
October 2010 period for which these data are readily accessible. In most hours, a notable
amount of available capacity remains unscheduled, and would be available if desired by
market participants that use dynamic transfers to ensure delivery of their energy.
From the above discussion of these results, there does not appear to be a strong reason for
further analysis of the impact of dynamic transfers of intermittent resources on intertie
utilization. Certainly, it is possible that some decreases in intertie utilization may occur.
However, the ISO has addressed this possibility through its proposals, including the use of
recallable transmission to dispatch dynamic resources beyond their transmission reservations
when other dynamic resources are not fully utilizing their reserved capacity.
CAISO/MAD/JEP
12
11/12/2010
CAISO Public
Figure 1: LAP Prices with Intermittent Resources within ISO vs.
Imported as Dynamic Transfer
80
70
$/MWh
60
50
40
30
20
0:00
12:00
0:00
12:00
0:00
Time
PG&E LAP, Internal Resources
SDG&E LAP, Internal Resources
SCE LAP, Dynamic Transfers
PG&E LAP, Dynamic Transfers + reservations
SDGE LAP, Dynamic Transfers + reservations
12:00
0:00
12:00
0:00
SCE LAP, Internal Resources
PG&E LAP, Dynamic Transfers
SDGE LAP, Dynamic Transfers
SCE LAP, Dynamic Transfers + reservations
Figure 2: Palo Verde Intertie Utilization with Dynamic Transfers
of Intermittent resources
3500
3000
2500
2000
1500
1000
500
0:00
12:00
0:00
12:00
0:00
12:00
0:00
12:00
0:00
1: Internal Intermittents
2: DT without Transmission Reservations
3: HASP Schedules + Reservations
4: RT Dispatch after HASP Reservations
5: RT Dispatch with New Dispatchable DT
CAISO/MAD/JEP
13
11/12/2010
CAISO Public
Figure 3: Four Corners Intertie Utilization with Dynamic Transfers
of Intermittent resources
1600
1400
1200
1000
800
600
400
200
0
0:00
12:00
0:00
12:00
0:00
12:00
0:00
12:00
0:00
1: Internal Intermittents
2: DT without Transmission Reservations
3: HASP Schedules + Reservations
4: RT Dispatch after HASP Reservations
Figure 4: Mead Intertie Utilization with Dynamic Transfers
of Intermittent resources
1400
1200
1000
800
600
400
200
0
0:00
12:00
0:00
12:00
0:00
12:00
0:00
12:00
0:00
1: Internal Intermittents
2: DT without Transmission Reservations
3: HASP Schedules + Reservations
4: RT Dispatch after HASP Reservations
CAISO/MAD/JEP
14
11/12/2010
CAISO Public
Figure 5: Duration Curves for Available Transmission Capability (ATC),
Scheduled Capacity, and Remaining Unscheduled Capacity at Palo Verde
3500
3000
MW
2500
2000
1500
1000
500
0
0
1000
2000
3000
4000
5000
Rank Order
HASP Limit
CAISO/MAD/JEP
HASP MW
15
Remaining Capacity
11/12/2010
CAISO Public
Attachment 2:
Modifications to WECC Base Case for Intermittent Dynamic Transfer
Capability Study
The CAISO has used the WECC 2018 Heavy Spring from the WECC website as the starting
point for the technical studies. New wind generation was added in the Solano and Tehachapi
areas. Since the base case didn’t have any new generation or transmission projects in the
SCE area and none of the Tehachapi upgrades, or Palo Verde-Devers upgrades were
modeled, the SCE area of the 2018 Heavy Spring case was replaced with the SCE area from
the 2020 Heavy Summer case of the 2011 CAISO Transmission Expansion Plan. Two base
cases were created from the 2018 Heavy Spring base case: (1) COI was loaded to its
maximum capacity of 4,800 MW and (2) WOR was loaded to 9222 MW. All changes to the
original WECC 2018 Heavy Spring base case are reflected in the following description.
CREATING A CASE FOR DYNAMIC SCHEDULE ANALYSIS
Starting Case – WECC 2018 Heavy Spring from the WECC website.
CHANGES IN THE SOLANO AREA
1) Added wind generation at Solano.
Turned on generation (existing) that was modeled off, and dispatched it at maximum:
Bus 32169
Bus 32172
Bus 32171
Bus 32177
Bus 33170
SOLANOWP
HIGHWNDS
HIGHWND3
SHILO
WINDMSTR
100 MW
162 MW
38 MW
300 MW
37.6 MW
Subtotal – 637.6 MW
2) Added new wind generation projects at Solano
A) Project Queue # 222 and associated transmission
Bus 32179
T222
78.2 MW
B) Project Queue # 039 and associated transmission
Bus 32190
Q039
200 MW
C) Project Queue # 113 and associated transmission
Bus 32188
P0611G
30 MW
D) Project Queue # 108 and associated transmission
Bus 32186
P0609
128 MW
Subtotal – 436.2 MW
CAISO/MAD/JEP
16
11/12/2010
CAISO Public
Total added at Solano 1073.8 MW
Added upgrades because of overload: second Bird Landing-Shilo 230 kV line
Reduced existing generation to compensate for generation additions: turned off Delta Energy Center
(DEC) 880 MW. The rest of the additions went to swing bus (Pittsburg 7)
There is also existing wind generation in Las Positas and Tesla areas, but it wasn’t changed it because
it is not in Solano. It is modeled at 49 MW out of 369 MW maximum.
CAISO/MAD/JEP
17
11/12/2010
CAISO Public
CHANGES IN THE TEHACHAPI AREA
Since the WECC Heavy Spring case didn’t have any new generation or transmission projects in the
SCE area and none of the Tehachapi upgrades, or Paloverde-Devers upgrades were modeled, the SCE
area of the 2018 Heavy Spring case was replaced with the SCE area from the 2020 Heavy Summer
case of the 2011 CAISO Transmission Expansion Plan. The SCE load was scaled down to the level of
the 2018 Spring case - 15813 MW, from 28422 MW in the Transmission Expansion Plan case.
The following new generation projects at Tehachapi were added, together with the associated
transmission upgrades. All these projects were modeled as dispatched at the maximum output.
BUS-NO
24249
24250
24257
24258
24259
24279
24280
24281
24282
24262
24269
24270
24271
24272
28313
28555
28556
28089
28090
94658
28034
28044
28270
28271
28272
28273
24270
28014
28294
28295
NAME
eastwnd1
eastwnd2
westwnd1
westwnd2
westwnd3
skyrivr1
skyrivr2
skyrivr3
skyrivr4
TEHACHAP
tehachmm
tehachmm
tehachr1
tehachr2
TOT185GN
wndt179a
wndt179b
wndt108a
wndt108b
TOT342_1
WNDT146
wndt153
wndt151a
wndt151b
wndt151c
wndt151d
tehachmm
TOT155
wndt161a
wndt161b
CAISO/MAD/JEP
KV
0.6
0.6
0.48
0.48
0.48
0.48
0.48
0.48
0.48
66
0.48
0.57
0.48
0.48
1
0.57
0.57
0.57
0.57
0.69
1
1
0.57
0.57
0.57
0.57
0.57
1
1
1
ID
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
PGEN
30
30
7
7
7
18.2
18
19.8
20.9
35
41.8
1.5
14.9
21.2
72.7
214.5
82.5
150
150
150
51
51
85
85
85
85
35
24
41.5
44.5
18
11/12/2010
CAISO Public
28296
28297
28298
28469
28470
28471
28472
28390
28391
28392
28393
28394
28395
28396
28397
28398
28399
28400
28401
28443
28444
28445
28446
28447
28448
28449
28450
28451
28452
28453
28454
28455
28456
28480
28481
28482
28096
94989
94990
94991
94689
94690
wndt161c
wndt161d
wndt161e
wndt164a
wndt164b
wndt164c
wndt164d
wndt162a
wndt162b
wndt162c
wndt162d
wndt162e
wndt162f
wndt162g
wndt162h
wndt162i
wndt162j
wndt162k
wndt162l
wndt163a
wndt163b
wndt163c
wndt163d
wndt163e
wndt163f
wndt163g
wndt163h
wndt163i
wndt163j
wndt163k
wndt163l
wndt163m
wndt163n
wndt165a
wndt165b
wndt165c
wndt167
WDT270_a
WDT270_b
WDT270_c
wdt300_a
wdt300_b
CAISO/MAD/JEP
1
1
1
0.69
0.69
0.69
0.69
1
1
1
1
1
1
1
1
1
1
1
1
0.69
0.69
0.69
0.69
0.69
0.69
0.69
0.69
0.69
0.69
0.69
0.69
0.69
0.69
0.69
0.69
0.69
0.6
0.4
0.4
0.4
0.48
0.48
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
47.5
50.5
36
52.5
52.5
52.5
22.5
47
47
47
36
50
50
50
47
50
36
45
45
40
40
40
36
50
50
50
48
50
36
40
40
40
40
55
52.5
52.5
120
11
11
11
25
25
19
11/12/2010
CAISO Public
94691
94692
wdt300_c
wdt300_d
EQ
EQ
0.48
0.48
TOTAL
25
25
3556
Existing wind generation at Tehachapi was turned on and dispatched at maximum output.
BUS-NO
NAME
24465
MORWIND
24481
MIDWIND
24482 SOUTHWND
24483 NORTHWND
24484 ZONDWND1
24485 ZONDWND2
24486
BREEZE1
24487
BREEZE2
24437
KERNRVR
24456
BOREL
24457
ARBWIND
24458 ENCANWND
24459
FLOWIND
24460 DUTCHWND
24436 GOLDTOWN
24118 PITCHGEN
TOTAL
ID
KV
1
66
1
12
1
12
1
12
1
12
1
12
1
12
1
12
1
66
66
1
66
1
66
1
66
1
66
1
66
1
13.8 D1
PGEN
56
18
6.6
19.4
13.2
12.8
4.5
8
24
10
21.8
112.9
40.8
14
13
30
405
Thus, total wind generation at Tehachapi was modeled at 3961 MW.
To compensate for this additional generation, the following units were turned off or their output was
reduced compared to the generation dispatched in the 2020 Summer peak case (including proposed
solar and thermal generation):
For majority of these units, the output and status was modeled to match the spring case of 2018
In the SCE area:
bus #
Name
24003 ALAMT3 G
24004 ALAMT4 G
CAISO/MAD/JEP
kV
ID
18
18
Output, MW
3
4 reduced
20
315
149
11/12/2010
CAISO Public
24005 ALAMT5 G
20
5
24020 CARBGEN1
13.8
1
24062 HARBOR G
13.8
1
24089 MANDLY1G
13.8
1
24090 MANDLY2G
13.8
2
24108 ORMOND2G
26
2
24123 REDON7 G
20
7
24124 REDON8 G
20
8
24127 S.CLARA
66
1
24161 ALAMT6 G
20
6
24163 ARCO 5G
13.8
5
24164 ARCO 6G
13.8
6
24239 MALBRG1G
13.8
C1
24240 MALBRG2G
13.8
C2
24241 MALBRG3G
13.8
S3
24242 RERC1G
13.8
1
24243 RERC2G
13.8
1
24244 SPRINGEN
13.8
1
24299 RERC2G3
13.8
1
Big Creek-Mammoth hydro reduced to match
spring case
24324 SANIGEN
13.8 D1
24328 CARBGEN2
13.8
1
24329 MOBGEN2
13.8
1
24332 PALOGEN
13.8 D1
24340 CHARMIN
13.8
1
24714 ALTA 1G
13.8
1
24718 ALTA31GT
13.8
31
24720 ALTA41GT
13.8
41
24734 ALTA32GT
13.8
32
24735 ALTA42GT
13.8
42
24737 LUZ8 G
13.8
8
24738 LUZ9 G
13.8
9
24815 GARNET
115
QF
24856 WDT213G1
0.6
1
24857 WDT213G2
0.6
1
24921 MNTV-CT1
18
1
24922 MNTV-CT2
18
1 reduced
24923 MNTV-ST1
18
1 reduced
24924 MNTV-CT3
18
1
24925 MNTV-CT4
18
1 reduced
24926 MNTV-ST2
18
1 reduced
CAISO/MAD/JEP
21
470
15
90
215
215
700
200
470
40
470
40
40
43
43
50
13
13
14
50
225.3
6.7
15
20
3.6
15
55
65
65
65
65
80
80
144.8
12.1
11.6
150
50
100
150
50
100
11/12/2010
CAISO Public
25301
25302
28116
28121
28126
28132
28137
28142
28729
29002
29030
29041
29042
29060
29061
29101
29102
29103
29104
29105
29108
29180
29191
29201
29202
29203
29260
29290
29903
29951
29952
29953
94032
94068
94108
94111
94112
94114
94130
94135
94137
94184
CLTNDREW
CLTNCTRY
TOT131G4
TOT131G5
TOT131G6
TOT131G1
TOT131G2
TOT131G3
TOT180
HIDEDCT2
WDT164
IEEC-G1
IEEC-G2
SEAWEST
WHITEWTR
TOT032G1
TOT032G2
TOT032G3
TOT032G4
TOT032G5
TOT032G8
WINTEC8
WINTECX1
TOT135G1
TOT135G2
TOT135G3
ALTAMSA4
CABAZON
TOT041G6
REFUSE
CAMGEN
SIGGEN
TOT210
TOT242
TOT198_1
TOT199
TOT199
TOT199
TOT358L1
TOT278_A
TOT278_B
tot284_a
CAISO/MAD/JEP
13.8
13.8
0.6
0.6
0.6
0.6
0.6
0.6
13.8
15
0.57
19.5
19.5
115
33
13.8
13.8
13.8
13.8
13.8
13.8
13.8
13.8
13.8
13.8
13.8
115
33
18
13.8
13.8
13.8
13.8
18
0.5
0.5
0.5
0.5
16
13.8
0.48
0.48
1
1
EQ
EQ
EQ
EQ
EQ
EQ
1
1
EQ
1
2
S1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
6
D1
D1
D1
1
1
1
1
1
1
1
1
EQ
EQ
22
47.2
47.2
103.3
103.3
103.3
91.6
91.6
92.3
63.6
150
19
405
405
44.4
30
105
105
105
105
105
105
45.3
45.3
100
100
100
40
42.6
150
9.8
26.2
23.9
72.5
127.3
90.3
80.7
80.1
80.1
90.3
21.6
21.6
16.3
11/12/2010
CAISO Public
94185
94186
94187
94209
94210
94214
94215
94216
94217
94228
94229
94233
94234
94246
94247
94266
94267
94271
94272
94275
94276
94277
94278
94423
94424
94426
94427
94428
94429
94455
94465
94466
94486
94487
94488
94508
94521
94522
94523
94524
94526
94633
tot284_b
tot284_c
tot284_d
TOT345_1
TOT345_2
tot292_a
tot292_b
tot292_c
tot292_d
WDT315A
WDT315B
tot307_a
tot307_b
TOT333G1
TOT333G2
TOT211L1
TOT211L2
tot313_a
tot313_b
tot314_a
tot314_b
tot314_c
tot314_d
TOT335G1
TOT335G2
TOT337G1
TOT337G2
TOT338G1
TOT338G2
TOT254G1
TOT321L1
TOT321L2
TOT226L3
TOT226L4
TOT226L5
TOT349L1
TOT276L1
TOT276L2
TOT276L3
TOT276L4
T154
TOT223L1
CAISO/MAD/JEP
0.48
0.48
0.48
0.4
0.4
0.48
0.48
0.48
0.48
12.47
12.47
0.48
0.48
13.8
13.8
0.21
0.21
0.48
0.48
0.48
0.48
0.48
0.48
13.8
13.8
13.8
13.8
13.8
13.8
18
18
18
0.48
0.48
0.48
13.8
18
18
18
18
18
18
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
1
2
1
1
EQ
EQ
EQ
EQ
EQ
EQ
1
2
1
2
1
2
1
1
1
1
1
1
1
1
1
1
1
1
1
23
16.3
16.3
16.3
81.7
81.7
16.3
16.3
16.3
16.3
13.6
13.6
16.3
16.3
25.1
25.1
95.4
95.4
13.1
13.1
16.3
16.3
16.3
16.3
25.1
25.1
25.1
25.1
25.1
25.1
164.3
150.5
150.5
66.6
66.6
66.6
29.8
150.5
150.5
150.5
150.5
0
150.5
11/12/2010
CAISO Public
94634
94639
94640
94643
94645
94650
94654
94703
94704
94705
94706
94707
94708
94737
94738
94739
94740
94984
TOT223L2
TOT340_1
TOT340_2
TOT341_1
TOT341_2
TOT381_1
TOT381_2
WDT286A
WDT286B
WDT286C
WDT286D
WDT286E
WDT286F
WDT285A
WDT285B
WDT285C
WDT285D
TOT340B
18
0.48
0.48
0.48
0.48
0.4
0.4
0.31
0.31
0.31
0.31
0.31
0.31
0.31
0.31
0.31
0.31
0.4
1
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
EQ
150.5
90.2
89.5
106.5
105.8
76.6
76.6
15.9
15.9
15.9
15.9
15.9
15.9
15.9
15.9
15.9
15.9
32.7
Total generation in the SCE area in the 2020 Summer peak case was modeled at 19880 MW, load at
28442 MW, for the 2018 Spring case for the dynamic schedule study SCE generation is modeled at
9805 MW, load at 15813 MW. For comparison, the 2018 Spring case that was a starting case from
which the case for the dynamic schedule study was created, had generation in SCE modeled at 7763
MW, load at 15813 MW. The data for generation for all the cases includes irrigational pumps that are
modeled as negative generation.
Generation reduction in other areas compared to the 2018 Spring case:
SDG&E:
Encina 4
Encina 5
295 MW
320 MW
PG&E:
Humboldt
66.4 MW
Pittsburg 7 (swing bus)
generation reduced by 142.5 MW
Delta Energy Center (to accommodate Solano Wind) 880 MW
Gateway
195 MW
ESEC
92.4 MW
UCDMC
25 MW
Northwest:
Coulee
CAISO/MAD/JEP
696 MW
24
11/12/2010
CAISO Public
Chief Joe
306 MW
BC Hydro:
GMS
260 MW
Total reduction in generation in areas other than SCE - 3279 MW. Reduction in SCE area generation
compared with the Spring case to accommodate additional Tehachapi wind 1919 MW. Total reduction
in generation to accommodate additional wind generation 5198 MW. Addition of wind generation in
Solano and Tehachapi: 5035 MW
Reduction in losses in the case with wind generation compared to the 2018 Spring case 163 MW
To mitigate the overload caused by such a significant wind generation modeled in the case, the
following system upgrades were modeled in addition to the upgrades already included in the 2020
Summer Peak case from the CAISO Transmission Expansion Plan:
1) Four additional 34.5 kV transmission lines to accommodate the TOT108 project
2) Two additional 34.5/0.69 kV transformers to accommodate the TOT163 project
3) Second 230 kV transmission line between Tehachapi and Skyriver
4) Second and third 230 kV transmission lines between Tehachapi P and E-W-WILD
5) Second 230 kV transmission line between East-West-WILD and VI-WI
6) Second 230 kV transmission line between VI-WI and Vincent
7) Second Tehachapi 230/66/12 kV transformer
8) Second 66 kV line between Tehachapi P Tehachapi M
9) Fourth Tehachapi M 66/12.5 kV transformer
10) Second Midwind 66/12.5 kV transformer
11) Two additional Tehachapi P 230/66 kV transformers
12) Two additional Tehachapi M 230/66 kV transformers
13) Additional Northwind 66/12 kV transformer
Major Path Flows in the WECC 2018 Spring Case and with the wind generation added:
#
Path
case with wind
1 ALBERTA - BRITISH COLUMBIA
spring
case
-400
-400
0
0
-2270
-2500
4 WEST OF CASCADES - NORTH
4297
4344
5 WEST OF CASCADES - SOUTH
4554
4557
2 ALBERTA - SASKATCHEWAN
3 NW-CANADA
CAISO/MAD/JEP
25
11/12/2010
CAISO Public
6 WEST OF HATWAI
1199
1078
8 MONTANA - NORTHWEST
526
436
9 WEST OF BROADVIEW
844
788
10 WEST OF COLSTRIP
843
843
11 WEST OF CROSSOVER
877
860
-179
-235
598
-569
-148
-137
579
542
-171
-201
0
0
18
7
21 ARIZONA - CALIFORNIA
4655
3144
22 SOUTHWEST OF FOUR CORNERS
1256
1334
151
220
24 PG&E - SPP
-2
-4
25 PACIFICORP/PG&E 115 KV INTERCON.
58
56
26 NORTHERN - SOUTHERN CALIFORNIA
1813
2251
27 IPP DC
1006
1006
28 INTERMOUNTAIN - MONA 345 KV
23
26
29 INTERMOUNTAIN - GONDER 230 KV
23
20
30 TOT 1A
-19
-50
31 TOT 2A
236
305
31
23
33 BONANZA WEST
246
224
34 TOT 2B
414
530
14 IDAHO-NW
15 MIDWAY - LOS BANOS
16 IDAHO - SIERRA
17 BORAH W
18 IDAHO - MONTANA
19 BRIDGER W
20 PATH C
23 FOUR CORNERS 345/500
32 PAVANT, INTRMTN - GONDER 230 KV
CAISO/MAD/JEP
26
11/12/2010
CAISO Public
35 TOT 2C
0
0
36 TOT 3
439
467
37 TOT 4A
16
24
38 TOT 4B
236
208
39 TOT 5
567
539
40 TOT 7
100
114
73
38
222
84
43 NORTH OF SAN ONOFRE
1288
1561
44 SOUTH OF SAN ONOFRE
862
589
-1
0
5695
6744
47 SOUTHERN NEW MEXICO (NM1)
116
116
48 NORTHERN NEW MEXICO (NM2)
1711
1714
49 EAST OF COLORADO RIVER (EOR)
3769
3231
50 CHOLLA - PINNACLE PEAK
716
737
51 SOUTHERN NAVAJO
544
564
0
0
54 CORONADO - SILVER KING - KYRENE
881
903
55 BROWNLEE EAST
852
908
-169
-164
59 EAGLE MTN 230/161 KV - BLYTHE 16
-23
67
60 INYO - CONTROL 115 KV TIE
-52
-50
61 LUGO - VICTORVILLE 500 KV LINE
939
820
62 ELDORADO - MCCULLOUGH 500 KV
-87
88
18
4
41 SYLMAR - SCE
42 IID - SCE
45 CA INDEPENDENT - MEXICO (CFE)
46 WEST OF COLORADO RIVER (WOR)
52 SILVER PEAK - CONTROL 55 KV
58 ELDORADO - MEAD 230 KV LINES
63 PERKINS - MEAD - MARKETPLACE 500
CAISO/MAD/JEP
27
11/12/2010
CAISO Public
65 PDCI
3088
3098
66 COI
2819
3710
73 N JOHNDAY
6849
7733
75 MIDPOINT - SUMMER LAKE
706
762
76 ALTURAS PROJECT
101
101
77 CRYSTAL - ALLEN
250
251
78 TOT 2B1
311
392
79 TOT 2B2
104
139
24
79
1260
1241
13030
11837
80 MONTANA SOUTHEAST
81 CENTENNIAL
500 Southern CA Imports
Case with COI 4800 MW
Turned back on:
Northwest:
Coulee
Coulee
Chief Joe
Add John Day
696 MW
219 MW
306 MW
278 MW
BC Hydro:
GMS
Total
260 MW
1499 MW
Turned off :
LADWP:
Haynes 8
CAISO/MAD/JEP
200 MW
28
11/12/2010
CAISO Public
Valley8
Harper Lake
180 MW
100 MW
Arizona:
Gila River
Aguafria
439 MW
210 MW
SMUD
Cosumnes GT
165 MW
Total
1294 MW
Reduce flow on PDCI from 3000 MW to 2000 MW, reduced shunts on Sylmar
COI Flow 4769 MW
CAISO/MAD/JEP
29
11/12/2010
CAISO Public
Case with high West of River (WOR) Flow
WOR Limit is 10623 MW
Starting case – Spring 2018 with wind generation at Solano and Tehachapi added
WOR Flow 5695 MW
Changes to the case:
Reduce generation in Northwest and increase generation in Arizona and Nevada
Turned on Arlington 3 units 500 MW
Turned off Coulee 11, 12 ,13, 15 439 MW
Reduced Coulee 19 from 597 to 537 MW
WOR flow increased to 6092 MW
Turned on Paloverde 2 1382 MW
Turned off Chief Joe 5-15 = 76.6 x 11 = 842.6 MW
Turned off John Day 1-4 = 138.3 x 4 = 553.2 MW
Total reduced 1396 MW
Turned off another John Day to keep swing up 138.3 MW
WOR Flow is 7157 MW
COI 1488 MW, PDCI 3100, need to make COI more
Reduced PDCI to 2000 MW, COI 2270 MW. Reduced shunt at Sylmar
WOR Flow became 7340 MW
Add generation in Arizona
Added DRPP unit 2 (was off) 500 MW
Took off gen in Canada (BC) reduced REV from 424 to 200 MW
KMO 1,2 , 3 300 MW
PCN 13 G1 160 MW
WOR 7654 MW, COI 1857 MW
Add generation in Nevada
HACC 1 100 MW was off
HACC 3 increased from 50 MW to 150 MW
Took off gen in LADWP HLSP 2 (Harper Lake) 100 MW
BCON 18 G 100 MW
WOR 7846 MW, COI 1863 MW
Took off more in LADWP
CAISO/MAD/JEP
30
11/12/2010
CAISO Public
Haynes 8 200 MW
Increased in AZ Harquahala 215+120+215 = 560 MW
Take off in PG&E Gilroy Cog 41.5 MW
Cosumnes 1 165 MW
WOR Flow 8344 MW
Turn on Four Corners 3 200 MW
Turn off LADWP Valley 6 70 MW
Haynes 9 156 MW
WOR Flow 8504 MW
Added TOT 226 66.6 x 3 = 199.8 MW (at Eldorado, SCE)
Took off in LADWP
MAG ST 80 Mw
Grays 3,4 ,5 5+12.6x2 = 30.2 MW
Haynes 10 156 MW
WOR Flow 8714.7 MW
Added TOT 321 264.4 MW (w/ aux load) at Red Bluff
WOR flow 8930 MW
Turn off in PG&E
La Paloma G1 230 MW
WOR Flow 8948 MW
Turned on TOT 198 at Red Bluff 90.3 MW
TOT 199 80.7 + 80.1 + 80.1 = 241 MW
WOR Flow 9220 MW
Took off PG&E
WEC1 ct 59.8
DVRA GT 1 45 MW
DUK Moss 5 166 MW
WOR Flow 9225 MW
Dynamic renew2.dyd
Above limits
CAISO/MAD/JEP
31
11/12/2010
CAISO Public
Yucca exciter bus 14963, Navajo 2 governor, reduced from 805 to 800 MW
WOR Flow 9222 MW
Error in dyd file, Yucca 1 and 2 are 13.2 kV, not 13.8
Reduced Yucca 3 Vsched to 0.98
CAISO/MAD/JEP
32
11/12/2010