20240826AVU to Staff Attachment 9C Attachment B_CONFIDENTIAL Avistas EIM Benefit Methdology_Oct_2022.pdf

CONFIDENTIAL
AVISTA CORPORATION
STATE OF IDAHO
CASE NO. AVU-E-22-11
ANNUAL POWER COST ADJUSTMENT (PCA)
COMPLIANCE FILING
AVISTA'S ENERGY IMBLANCE MARKET (EIM) BENEFIT
METHODOLOGY

CONFIDENTIAL
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EIM Benefit Methodology
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Table of Contents
Table of Contents
DocumentVersion Control...................................................................................................................3
DocumentSign Off...............................................................................................................................3
1.0 Introduction .............................................................................................................................4
2.0 Existing Methodologies Summary& Reference.........................................................................5
2.1 CAISO Benefit Methodology.........................................................................................................5
2.2 Power Settlement Benefits Methodology ....................................................................................5
3.0 Avista's EIM Benefit Methodology Overview............................................................................6
4.0 Gap Analysis of CAISO's EIM Benefit Methodology...................................................................7
4.1 Commitment Costs in EIM Are Not Included................................................................................7
4.2 Benefits Not Adjusted for Third Party Loads and Generation ......................................................7
4.3 Discrepancy between Resource Bids and Actual Costs ................................................................7
4.4 Added Maintenance Cost driven by Increased Cycling.................................................................9
4.5 Incremental Cost of Donated Transmission by Avista Merchant .................................................9
4.6 Impact from Market Errors...........................................................................................................9
4.7 Other EIM Benefit Related Components ....................................................................................10
4.8 Wind Contract Curtailment Cost.................................................................................................10
5.0 Avista's EIM Benefit Methodology Details .............................................................................. 10
5.1 Part 1: Execute Initial Benefit Calculation...................................................................................10
5.2 Part 2: Validate Output,Adjust Input and Rerun as Necessary..................................................10
5.3 Add Components Excluded from CAISO Benefit Calculation......................................................11
6.0 Future Methodology Considerations....................................................................................... 13
6.1 Variable Energy Resource (VER) PMax(max generation of resource) Review...........................13
6.2 Commitment Cost Adjustments..................................................................................................14
6.3 FMM Settlements Value is not Considered ................................................................................14
6.4 Impact of BPA Rate of Change Constraints.................................................................................14
6.5 Third Party Loads and Generation is Included at BAA Level.......................................................14
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Document Version Control
Version Date Author Comments
1.0 07/07/2022 Xin Shane This includes revised content from Xin Shane, Robert
Follini, Brandon Taylor, Brian Holmes (Utilicast), Russell
Miller(Utilicast)
2.0 07/27/2022 Xin Shane Reviewed and Edited by Clint Kalich
Document Sign Off
Person Role Signature Date
Xin Shane Manager, EIM Settlement&Analytics 10-06-2022
Robert Follini Manager, Power Trading 10-06-2022
Brandon Taylor Organized Market Manager 10-06-2002
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1.0 Introduction
Avista joined the Western Energy Imbalance Market (EIM) on March 2, 2022. Based on previous studies
by Energy and Environmental Economics (H) and CAISO, Avista expects to realize multiple benefits
through EIM participation. This document details Avista's approach to quantifying those benefits.
Avista's EIM Benefit Methodology described within is based on CAISO's EIM Benefit Methodology,
adjusted to more accurately quantify Avista's EIM benefit. Previous entrants to the Western EIM have
utilized different techniques for calculating EIM Net Benefit,thus no standard has been established among
EIM entities. Beyond the CAISO EIM Benefit Methodology, Avista contracted with Energy and
Environmental Economics (H) in the fall of 2017 to perform an exploratory EIM benefit analysis. Further,
Avista had multiple conversations with other western utilities who had previously joined the Western EIM.
This document is structured into the following sections:
1. Existing Methodologies Summary& Reference
2. Avista EIM Benefit Methodology Overview
3. Gap Analysis of CAISO's Benefits Methodology
4. Avista's EIM Benefits Calculation Process
5. Future Methodology Consideration
Avista believes its EIM Benefit Methodology is aligned with the spirit of the broader CAISO EIM Benefit
Methodology and is generally congruent with other EIM entities' methodologies.
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2.0 Existing Methodologies Summary & Reference
This section contains descriptions of some existing methodologies.
2.1 CAISO Benefit Methodology
CAISO publishes quarterly benefits for each EIM participant. Detailed calculations are described in the
Methodology document attached as Appendix A.
2.2 Power Settlement Benefits Methodology
Power Settlements has developed a methodology to shadow the CAISO's EIM benefits. Detailed
calculations are described in the Methodology document attached as Confidential Appendix B.
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3.0 Avista's EIM Benefit Methodology Overview
This section contains a description of the Methodology Avista will use to calculate EIM Benefits.
The CAISO EIM Benefit Methodology is relatively straightforward and intuitive. However, in its attempt to
create a single methodology for all EIM participants, certain components do not apply well to Avista and
some important components are excluded, leaving discrepancies. Discrepancy examples are provided
later in this document. Each can mask costs or over-state benefits. Nevertheless, this methodology is
widely known and thus serves as a starting point for Avista's approach.
Avista built upon CAISO's EIM Benefit Methodology by leveraging the vendor-supplied solution
"SettleCore," allowing Avista to "shadow" CAISO daily settlement statements and validate for correctness
and completeness. Further, SettleCore provides "Shadow EIM Benefit" functionality, enabling Avista to
calculate potential benefits. Several other EIM entities also use the SettleCore module to evaluate their
expected Western EIM Benefits. Avista will continue evaluating its EIM Benefits Methodology and refine
it as improvements are identified.
The flow chart below summarizes Avista's current EIM benefit calculation process, which will be further
detailed in section 5.0:
Part 1: • Run SettleCore shadow
Execute Initial benefit calculation
Benefit Calculation
'Validat_ • CAISO discrepancy:5.2.1
Adjust Input and • Cost curve validation:5.2.2
ComponentsRerun as Necessary
Part 3:
Increased cycling costs: 5.3.1
Add
.-.
Incremental cost of donated transmission:5.3.2
from
CAISO Benefit Market error: 5.3.3
Calculation • Other Benefits: 5.3.4
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4.0 Gap Analysis of CAISO's EIM Benefit Methodology
Through discussions with other EIM entities and internal analyses, Avista has identified several areas for
which the CAISO EIM Benefits Methodology does not align well with Avista. A list of key divergences is
identified and addressed in this document. Some of the identified items are included in Avista's EIM
Benefit Methodology scope, while others are excluded with justification. The in/out-of-scope decision is
based on the estimated magnitude of impact on EIM benefits, and the amount and availability of data.
4.1 Commitment Costs in EIM Are Not Included
The CAISO EIM Benefit calculation considers commitment costs for ISO BAAs (Balancing Authority Areas),
and not EIM BAAs like Avista. Thus, an EIM benefit calculation for Avista using CAISO's methodology
incorrectly inflates or deflates benefits depending on the net load imbalance direction. SettleCore, from
Avista's chosen vendor, also does not consider Avista's commitment costs.
4.2 Benefits Not Adjusted for Third Party Loads and Generation
The Avista BAA includes Avista load and 3rd party loads served by Avista under contract, including those
of the Bonneville Power Administration (BPA). CAISO's methodology incorrectly attributes benefits and
costs accruing to all loads to the Avista BAA.
Depending on the time of year, BPA loads alone can represent roughly 15% of the total Avista BAA load.
Any benefits methodology should pass load-related charges to the 3rd party load. Therefore, any EIM
benefit estimate associated should accrue reductions in the cost of serving BPA and other 3rd party loads
to those loads, not Avista.
Non-BPA 3rd party load served by the Avista's merchant function under contracts includes Pend Oreille
PUD, Clearwater, Inland Paper and Kaiser.The EIM charge/payment associated with these contracts is
currently absorbed by Avista, but going forward it is reasonable to assume that contracts may be
modified to reflect best efforts to transfer these impacts to the 3rd party.As long as the contract follows
the contracting price, and not binding with EIM terms,this is not a relevant item to consider for Avista's
EIM Benefit calculation.
4.3 Discrepancy between Resource Bids and Actual Costs
The CAISO's EIM Benefit Methodology assumes that incremental Energy Bids, including mitigated
Incremental Energy Bids, represent an entity's true cost structure.There are several reasons that this
may not be true.
1. Incremental costs are represented in ways other than in the incremental Energy Bid (e.g.,
Startup or Minimum Load Bids).This is highlighted in Section 4.1.
2. Mitigated Incremental Energy Bids can understate Avista's true costs, including opportunity
costs.
3. Resource-related dispatch limitations require bids be placed strategically. Some further
details around bidding costs other than true opportunity are detailed in Section 4.3.1
4.3.1 Equipment Limitations Preventing Dispatch to Market
The EIM market design cannot represent certain capabilities and constraints of Avista's generation fleet.
Avista has spent a great deal of time determining how to represent its capabilities, costs and constraints
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to EIM to ensure the best operational and financial outcomes in its marketplace. However, some
techniques used result in inflated benefits within the relatively simplistic CAISO counter-factual dispatch.
An example scenario is benefits being erroneously credited to Avista for the commitment of either its
Colstrip or Kettle Falls Biomass plants. Avista's modified methodology identifies these CAISO-assigned
benefits and deduct them as appropriate.This section explains this risk.
Avista is a joint owner of Colstrip units 3 and 4.Avista has the rights to dispatch this plant on a 15-minute
basis with 20 minutes notice. However,the Colstrip plant is not capable of responding to CAISO's 5-minute
market instructions.Thus,should Avista need to bid Colstrip in support of its Flexible Ramping Sufficiency
or Bid Range Capacity tests, Avista would likely do so at a higher cost to avoid 5-minute dispatch
instructions. Even with this bidding strategy, should the Avista EIM benefits counter-factual analysis
dispatch Colstrip, while in reality CAISO did not, CAISO's benefit calculation would incorrectly attribute
the benefit of the avoidance of commitment costs when in fact we did not avoid a commitment.
Erroneous benefits can also arise within the Flexible Ramping Sufficiency Test itself. Avista must
demonstrate adequate capacity and flexibility via this test, and the Capacity Resource Sufficiency Test,
each hour—which Avista does via its bids. In situations where Avista needs to count Colstrip flexibility or
capacity, Avista may bid Colstrip at an inflated bid price (e.g., $100 instead of the cost, which we can
assume to be $25 in this example) because Avista will be unable to comply with market dispatches on a
5-minute basis and would need to ensure its bid would contain enough revenue to offset CAISO penalties
associated with Colstrip's inability to follow 5-minute dispatch direction.
To the extent the CAISO EIM Benefits counter-factual dispatched Colstrip,while the actual market solution
did not, it would appear EIM provided benefits. However, no benefit is received. Pre-EIM operations, if
Avista had been short and needed to dispatch Colstrip intra-hour, it would do so at the dispatch cost. As
a result, any apparent EIM benefit for Colstrip is due to limitations around: the Colstrip plant, EIM, and
the CAISO EIM Benefit counter-factual, and thus do not represent reduced operational costs to Avista.
The same conditions exist for the Kettle Falls biomass and Northeast plants.
4.3.2 Fossil Use Limits
Two Avista plants have use limits as a function of their air permits —the duct burners at the Lancaster
plant,and the Northeast CT.At Lancaster,the limit applies on an annual basis; at Northeast CT the limit is
daily.The EIM solution horizon is just 4.5 hours, much shorter than both permit limits, and so these limits
cannot be accommodated by the market directly and must be accounted for through our bidding strategy.
Should Avista need to bid in either resource in support of the Flexible Ramping Sufficiency Test or the Bid
Range Capacity Test, Avista must do so at bid prices above our short-term costs to account for any
penalties incurred when we are unable to meet EIM-directed dispatch levels due to these limitations.Any
CAISO EIM benefit counter-factual based on these higher bid curves would result in over-stated benefits.
4.3.3 Hydro Use Limits
Avista owns a significant number of hydro resources, and they play a key role in daily EIM operations.
CAISO's EIM market was designed around thermal plant operations, not hydro. Their operational
flexibility and limits cannot be represented in the EIM and so our bids must reflect the risks of EIM
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dispatch directions violating our capabilities.These bids can differ from our actual generation price,
causing the CAISO EIM benefit calculation to overstate benefits.
4.4 Added Maintenance Cost driven by Increased Cycling
Avista has a respectable amount of ramping capability within its fleet, which is called upon by EIM at
various times throughout the day. This leads to more resource movement than Avista has historically
experienced. Like its peers, Avista has noticed a significant increase in resource movement. This
movement leads to increased maintenance costs. Avista requires more time to better estimate these
potential increases in maintenance cost and include them in its bidding strategies.
4.5 Incremental Cost of Donated Transmission by Avista Merchant
The costs related to Avista EIM-donated transmission reduces our benefit and should reduce
CAISO/SettleCore benefit calculations.Two categories are associated with donated transmission:
• Lost transmission revenues: This requires the identification of the transfer enabled by the
redirect, and the estimated value of selling that amount of transmission.
• New transmission purchases specifically used to enable EIM Transfers: identify the amount of the
purchase intended for EIM vs. Non-EIM.
4.6 Impact from Market Errors
The EIM relies on input models and data to calculate its market solution.These inputs are numerous and
complex.Avista has noticed multiple instances where one or more modeling or data input were incorrect
and expects this behavior to continue in the future. As a result of these issues, market dispatches, ETSR
(Energy Transfer System Resource) transfers, and LMPs (Locational Marginal Prices) are not always an
accurate representation of what EIM participants' costs would have been absent EIM. In some cases,
Avista may be able to successfully argue for a modification through a settlement dispute, or CAISO may
perform a price correction. In many cases, CAISO is unwilling or unable to make a correction.
In one recent example of a utility that joined in 2021, CAISO incorrectly modeled a linkage between a
generator and a dynamic export.The result was a false shortage of hundreds of MWs for several hours in
the BAA. The EIM market solution backfilled this apparent shortage, creating operational issues and
significant charges for the affected utility. CAISO was unable or unwilling to correct this issue because
other entities relied on the same market solution and provided energy incorrectly as identified by the EIM
solution.This was a significant loss for the entity not correctly reflected in CAISO's EIM benefit calculation.
In another example, a May 2022 CAISO price correction had a direct negative financial impact on Avista.
We followed CAISO dispatch, leading to profitable operation of Avista resources. However, a CAISO price
correction later expunged those profits, creating significant lost opportunity costs having a direct impact
on Avista's financial performance. This impact was not accounted for in CAISO's EIM benefit calculation.
Unfortunately, modeling and data errors oftentimes are undetected. However, to the extent Avista can
identify the errors with its modified benefits calculation, we will ensure accurate accounting. The market
error identification process will evolve over time. Avista's merchant group will leverage the recurring
CAISO market quality call and CAISO EIM Market Analysis report to identify market errors daily. A log will
be kept, and further analysis of the impact from market errors will be conducted between the merchant
and settlement group.
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EIM Benefit Methodology
4.7 Other EIM Benefit Related Components
While Avista earns greenhouse gas (GHG) payments from market participation, it is critical that Avista has
enough credits to meet its GHG compliance requirements. Any costs of GHG credit purchases will offset
benefits assumed in the CAISO EIM calculation.
4.8 Wind Contract Curtailment Cost
Avista wind resources are all controlled through contract; we do not own any wind resources directly.
When wind generation is curtailed, Avista must pay the resource owner the curtailed energy. If the
curtailment is directly caused by EIM market dispatch,the associated cost will be considered as an offset
component of the EIM benefit calculation. It is not considered by the CAISO EIM benefits methodology.
Avista expects other items impacting the benefit calculation are yet to be discovered. We will continue
monitoring for these impactors.
5.0 Avista's EIM Benefit Methodology Details
Avista's EIM Benefit Methodology is a three-part process developed to address findings in the Gap
Analysis of CAISO's EIM Benefit Methodology.Avista executes this process monthly.
5.1 Part 1: Execute Initial Benefit Calculation
The initial execution of the shadow benefit calculation uses the SettleCore software and CAISO inputs.
Avista expects to receive CAISO's benefit calculation output file three weeks after the trading month ends.
5.2 Part 2: Validate Output, Adjust Input and Rerun as Necessary
After the initial shadow benefit calculation runs,Avista receives the CAISO and SettleCore benefit
calculation files and a thorough review and validation can be conducted. During review,the SettleCore
shadow benefits calculation is rerun with any identified input adjustments, mainly resource bids.
5.2.1 CAISO Discrepancies
Avista's settlement team reviews and compares CAISO Benefit calculation output with the SettleCore
Benefit calculation output, as this comparison forms the basis for Avista's methodology.Typical review
areas include:
• Total benefit value.
• EIM transfer revenue.
• EIM dispatch cost.
• Counterfactual dispatch cost.
• GHG Revenue.
• GHG transfer revenue.
• Flex transfer revenue.
Avista applies the following thresholds to determine whether a further investigation is warranted:
a) Discrepancy in percentage of total CAISO Benefit value for the month >2.5%
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b) Absolute value of discrepancy for the month >$100,000
If these thresholds are not met, no further adjustments or analyses are completed.
5.2.2 Cost Curve Adjustment
Most bids submitted to the EIM deviate from actual costs,for reasons described in Section 4.3.Avista will
address this by overwriting bids sourced from the CAISO SIBR(Scheduling Infrastructure& Business Rules)
with a value more closely reflecting its actual operating costs.The specific resources for which this applies
to are:
• Colstrip
• Kettle Falls Steam Turbine
• Northeast Combustion Turbine
• Long Lake (Ambient Rerate/derate)
• Little Falls (Ambient Rerate/derate)
• Boulder Park (Ambient Rerate/derate)
• Lancaster
• Noxon Rapids
• Cabinet Gorge
• Mid-C Contracted
Process:
1. Use Avista Merchant logs or other communications to identify where bids deviated from
opportunity cost.
2. In an internal workshop format or email communication,Avista Merchant and Settlement groups
review effective bid costs to confirm if any input adjustments are needed (Avista expects a more
systematic approach to be established, after the process is executed multiple times. As various
entities use a different price basis for adjustments, so too will Avista establish its own basis based
on accumulated EIM business expertise).
3. If an adjustment is necessary, Avista updates inputs for a potential rerun of the shadow benefit
calculation.
5.3 Add Components Excluded from CAISO Benefit Calculation
Once a review has established confidence in the shadow benefit calculation, a simple
addition/subtraction calculation is performed to include costs or benefits not addressed in the CAISO
Benefit Methodology.
5.3.1 Increased Cycling Maintenance Costs
Avista needs adequate time participating in EIM to evaluate the effect of increased cycling on the
maintenance requirements for the Avista generation fleet, so this cost component will likely affect the
EIM benefit in 2023. Therefore, a process is defined and will be further developed through practice over
time. The method includes detailed monitoring and inputs from the GPSS group and calculations
performed by the merchant group.
Avista has implemented a standard method of tracking cycling data, where a consistent interpretation of
data is enforced:
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• Mileage: MW "distance" that the unit ramps. It is calculated by comparing the metered actual
every 5 minutes to the metered actual in the prior 5 minutes. The MW value is calculated when
that difference is greater than 1 MW in an absolute value sense. These values are summed over
the period, which, at least initially, is monthly.
• ON/OFF: Measurement of breaker operations when generating plants are being cycled online
and offline.
The data is summarized in EIM Gen Mileage report in PI data system, and below is an example
screenshot
• -
0 r r r
® NOXON
Monthrnp ABS MW
Firs
Jul 175 15.758 0 0 346 ,32 3.327 , 0.0 0.0 58.2 233 Max 93.8
O May 738 61.331 0 1 2.329 121 18.746 0.0 0.3 435.6 1027 199.7
Mar 547 42.430 0 36 2.094 184 20.833 0.2 35.5 349.2 69.0 95.3
Jan 402 32.234 0 32 909 101 9.310 0.3 24.9 240.2 849 54.3
Dec
292 25.004 0 30 504 5 6.930 0.0 15.4 110.8 1252 43-3
Oct
Sep 339 29.047 0 30 608 5 8.249 0.1 11.9 153.8 116.2 6L1
Jul 319 27.926 0 26 841 9 8.220 0.1 7.8 155.9 82 5 75 1
Due to the level of effort the evaluation process requires, Avista will likely evaluate increased cycling
maintenance costs on an annual basis to determine if adequate data exists to use in its EIM benefit
calculations.
5.3.2 Donated Transmission Incremental Costs
The Avista Merchant periodically has residual transmission from day-ahead and real-time market
optimization activities. After these markets close, the unused transmission typically has zero terminal
value.With Avista's entrance to EIM,Avista plans to donate this transmission to the EIM to benefit Avista's
load and marketing at zero cost. However, there may also be instances (due to transmission constraints
or optimization opportunities in the region) where Avista would allocate transmission earlier in the
optimization cycle to EIM.
To account for these activities, Avista has created an EIM Transmission Cost Book in their ETRM (Energy
Trading Risk Management) system to capture these types of donations and transfer any costs the
Merchant incurs to this book.Avista's Merchant will calculate the value of the quarterly early optimization
cycle transmission donations and provide them to the Avista staff preparing the Avista EIM Benefits
Report. In addition, Avista staff will note in the quarterly process log the values of any donated
transmission.These values will then be appropriately removed from the Avista EIM Benefit calculation.
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5.3.3 Market Error Corrections
"One-off" CAISO errors can impact Avista benefits. Where Avista identifies significant one-off errors by
CAISO,we will apply corrections to the benefits calculation.
We will use at least two general avenues to identify these market errors:
• From an operations perspective,Avista Merchant group will report market errors.
• From a settlement perspective, a valid CAISO dispute that isn't financially resolved will be a
source of record for the benefit adjustment.
When a significant market error is identified, a thorough financial analysis will be conducted. Any
financial impact from market errors will be deducted in the final benefit calculation. May 2022 CAISO
price correction financial impact analysis will be an excellent example to demonstrate this process.
5.3.4 GHG Offset Purchase Cost
The monthly GHG offset cost will be provided by Avista Merchant group. Avista's GHG analysis will
leverage a standard report in the PRSC (Participating Resource Schedule Coordinator) application.
5.3.5 Wind Curtailment Cost
Compensable curtailed energy charges will be reviewed monthly, upon receipt of Clearway invoices.The
amount associated with the compensable curtailed energy will be directly deducted from the final
benefit.
6.0 Future Methodology Considerations
Avista will continue refining its EIM Benefit methodology, identifying opportunities to further improve
the accuracy of its EIM benefit calculation. As a new entrant,we will be on a steep learning curve for
some time. With limited experience in the market,the focus required on the daily EIM operations limits
the scope of consideration in our initial EIM Benefit methodology. Below are some opportunities
identified for future consideration.
6.1 Variable Energy Resource (VER) PMax (max generation of resource) Review
Avista has preliminarily identified discrepancies between its VER(Variable Energy Resource) PMax in CMRI
(Customer Market Result Interface) and the ADS (Automatic Dispatch System) Dispatch report, due to a
data gap caused by data granularity issues in the CAISO VER forecast report. This leads to a potential
inaccurate benefits calculation when a VER resource is involved in the counter factual dispatch run at the
time interval.To accurately estimate this impact, and properly factor the effect in our benefit calculation,
a large data analysis effort is required. The proposed process will consist of: (1) performing a data gap
analysis, and (2)taking one of the following actions, should an adjustment be required:
• Adjust inputs for the rerun of the Shadow benefit calculation.This approach will require vendor
engagement and support, and we have not engaged in a conversation with the vendor on this
topic yet.
• Post process SettleCore Benefit Calculation output file to calculate the over-estimated benefit
portion.This approach will require a complex data model to be built.
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6.2 Commitment Cost Adjustments
As shared earlier in this document,the CAISO Benefit Methodology doesn't consider unit commitment
cost, negatively impacting EIM dispatch cost and the counter factual dispatch cost calculation.Two areas
should be analyzed:
• CAISO's ISO Commitment Cost Report captures start-up costs, minimum load costs, multi-stage
generation transition costs, and shut down costs for market committed resources.This report
can potentially be used to quantify the commitment cost that needs to be added to the EIM
dispatch cost. Start-up costs are straightforward to calculate, yet complications are expected
with the minimum load cost associated with the market-committed resource.
• An approach considering commitment cost in the counter factual cost calculation likely will be
done by post processing with the SettleCore shadow benefit run output file,with a calculation
model yet to be built.
6.3 FMM Settlements Value is not Considered
When EIM dispatch and counter factual dispatch costs are calculated, only RTD dispatch is considered.
The impact from RTPD dispatch is unknown but might negatively impact benefit calculations.
6.4 Impact of BPA Rate of Change Constraints
Avista relies on the BPA transmission system to move Mid-C generation and Coyote Springs generation
across BPA and to Avista's BAA.There are many constraints associated with this transmission. Some of
these are reflected through a set of"rate of change constraints". These constraints limit the change in
the dispatch between the FMM solution and the RTD solution. When these constraints are binding,they
will impact the LMPs that Avista pays and receives.
In current pre-EIM operations, Avista has certain contractual rights and obligations but is not directly
subject to financial impacts from the Rate of Change Constraints. Avista is attempting to learn more
about these constraints and how they will impact benefits achieved from EIM v. current operations, if at
all.
6.5 Third Party Loads and Generation is Included at BAA Level
As mentioned previously, BPA can account for up to roughly 15%of the AVA BAA load during specific
periods. Non-BPA loads also affect the calculations. This could impact Avista's EIM Benefits calculation.
Options have been identified to quantify the BPA portion in the EIM benefit calculation number
produced by the SettleCore Shadow Benefit Calculation.
Option 1: Assume that a load-ratio share of the benefits is accruing to BPA. In this approach,Avista
would take the Adjusted EIM Benefits and pro-rate them based on a load ratio share.This would likely
be derived from the hourly Load Meters used in sub-allocations.The primary value of this approach is
simplicity. However, a significant drawback is that generation profits and fuel savings primarily accrue to
Avista. BPA would only benefit from reduced costs to serve its imbalance around its hourly schedule.
This method likely will understate Avista benefits.
Option 2: Evaluate BPA cost of imbalance directly using the LMP from the market and from the counter-
factual analysis.This approach would use the imbalance directly from sub-allocations multiplied by the
price differential and then deducted from the Adjusted EIM Benefits and provide a much better
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'All�
�u1VISTA' EIM Benefit Methodology
estimate of BPA benefits. However, it is unclear if counter factual LMP data will be available to support
this option; and, if so, if and how it can be normalized to the hourly LMP that BPA pays.
At this point, critical data availability will impede the analysis of a reasonable ratio assumption to net
out the BPA portion of the benefit.Therefore,further learning and investigation are required to
evaluate this component.
Copyright 2022, Avista October 2022
All rights reserved. Proprietary and confidential. Page 15 of 15
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CONFIDENTIAL
AVISTA CORPORATION
STATE OF IDAHO
CASE NO. AVU-E-22-11
ANNUAL POWER COST ADJUSTMENT (PCA)
COMPLIANCE FILING
APPENDIX A
EIM QUARTERLY BENEFIT REPORT METHODOLOGY
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EIM Quarterly Benefit Report Methodology
Effective with Q1 2021 EIM benefits report
Prior to the creation of this document, the methodology for the benefits calculation was posted
in a technical bulletin and in the benefit report itself. This document consolidates these prior
materials into a concise paper for easier understanding of how the EIM benefits are calculated.
The total EIM benefit is the cost saving of the EIM dispatch compared with a counterfactual (CF)
without EIM dispatch. The counterfactual dispatch meets the same amount of real-time load
imbalance in each BAA without EIM transfers between neighboring EIM BAAs. For an EIM BAA,
the benefit can take the form of cost savings or profit or their combination. A BAA will be likely to
have energy cost savings when the BAA is importing energy economically, or its base
schedules are being optimized by the EIM. To the extent an entity base schedule is optimized
prior its submission into the EIM, the benefits may be lessened when compared to an entity that
has not submitted optimized base schedules into the EIM. A BAA will be likely to have an
energy profit when the BAA is exporting energy economically to other BAAs and being paid a
price higher than the bid cost. A BAA other than the ISO may also have a GHG profit when the
resource is allocated GHG MWs and is receiving GHG revenue based on marginal GHG cost
that is likely higher than its own GHG bid cost.
For each 5-minute interval, the EIM benefit for a BAA= counterfactual dispatch cost— (EIM
dispatch cost + transfer cost + flex ramp transfer cost) + GHG revenue — GHG cost. The
5-minute level EIM benefits are then aggregated each month with a multiplier 1/12 to convert
($/5 min) to a dollar amount.
EIM Benefit Calculation Components
EIM Dispatch Cost
The total dispatch cost for a BAA for an interval is the sum of all the unit level EIM dispatch
costs for that BAA for that interval.
For all BAAs other than CAISO, the dispatch cost only includes variable dispatch cost, i.e. the
bids submitted by the corresponding Scheduling Coordinator.
For the ISO's long start units, we only consider variable dispatch cost. For the ISO's short start
units, we use a generic cost formula, which includes variable dispatch cost, no load cost, and
startup cost. Specifically, the three-part cost for short start units includes:
• The variable dispatch cost of RTD, which is equal to the bid cost associated with the
delta instruction above or below the base schedule for each interval,
• the no load cost associated with the incremental dispatch, which is equal to the no load
cost divided by Pmax, then multiplied by the delta instruction from the base schedule,
• The startup cost associated with the incremental dispatch, which is equal to the startup
cost divided by the minimum online hours, then multiplied by the delta instruction from
base schedule divided by the Pmax.
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The purpose of this generic cost formula is to evaluate cost differences between EIM dispatches
and counterfactual dispatches without performing sophisticated unit commitment simulations.
Prior to Q1 2016, only variable dispatch cost was considered in the EIM benefit calculation. With
NV Energy joining EIM and improving the transfer capabilities from and to the ISO, we observed
a significantly increased transfer volume in EIM. The higher transfer volume cannot be
sufficiently replaced by resources online in EIM without committing or de-committing resources,
and hence the ISO adopted a three-part cost formula as of Q1 2016 to allow for unit
commitment decisions to better evaluate the production difference between EIM and the
counterfactual dispatch of the ISO. The unit commitment decisions were made only for short
start units that were not combined cycle units. The combined cycle units have complicated
models in EIM, so their counterfactual commitment status is fixed at the EIM commitment status
to avoid oversimplification.
We approximate the ISO's commitment costs by converting the startup cost and no load cost
into variable dispatch cost, assuming a committed short start resource will be fully loaded for
minimum online hours. For each supply segment, the corresponding three-part variable cost is
equal to
bid_price + no_load_cost/Pmax + startup_cost/min_up_hour/Pmax
Note the formula above converts startup cost (in unit $) and no load cost (in unit $/h) into
variable dispatch cost (in unit $/MWh). By doing this, the commitment for the ISO's short start
units can be determined based on the economic metric order of the three-part variable cost.
Transfer Cost
As a convention, select the importing direction as the default direction for a transfer, so the
importing transfer is positive and the exporting transfer is negative. The transfer cost is equal to
the transfer MW times the transfer price. For transfers involving the ISO in either the importing
direction or the exporting direction, the transfer price is the other BAA's LMP plus the shadow
price of the transfer. In doing this, the congestion rent on the transfer will be fully attributed to
the other BAA. For transfers involving two BAAs that are not the ISO, the transfer price will split
the congestion shadow price on the transfer in half. For an importing BAA, the transfer price is
the LMP of the BAA minus half of the absolute value of the transfer shadow price. For an
exporting BAA, the transfer price is the LMP of the BAA plus half of the absolute value of the
transfer shadow price. The transfer could occur in both the 15-minute market and the 5-minute
market. In this case, the transfer cost is 15-minute transfer* 15-minute transfer price + (5-
minute transfer— 15-minute transfer) * 5-minute transfer price for each 5-minute interval.
For the prices (LMPs) used in the EIM benefits, the calculation uses the corresponding ELAP
prices of each EIM area. For CAISO prices, the calculation uses the prices associated at the
corresponding scheduling points at the Malin, Palo Verde, El Dorado or Rancho Seco interties.
The specific scheduling price to be used among these intertie locations is in relationship to the
benefit calculated to a specific EIM area. For instance, when calculating the benefits between
PAC West and CAISO, the calculation will use Malin scheduling point price (CAISO side).
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Flex Ramp Transfer Cost
In 2016, the ISO implemented the flexible ramping products to replace flexible ramping
constraints. The flexible ramping products are available capacities to handle future load and
generation uncertainties, and include both the upward ramping capacity and downward ramping
capacity. They may be put aside in RTD to enhance dispatch flexibility. One BAA's flexible
ramping capacities in RTD may be helping other BAAs. In this case, the BAA that exports
flexible ramping products should receive payment from other BAAs to compensate the dispatch
cost of keeping flexible ramping capacities, and the BAA that imports flexible ramping products
should pay other BAAs to reflect its dispatch cost to handle future uncertainties. This is similar
to how energy transfer is treated in the EIM benefit calculation. Energy transfer is explicitly
modeled in EIM, while flexible ramping transfer is not. We need to calculate a BAA's flexible
ramping transfer. First, we allocate the system flex ramp award to each BAA in proportion to its
individual BAA requirement. Then we calculate the flex ramp transfer as the BAA's RTD flexible
ramping award minus its allocated share. The flex ramp transfer cost is equal to the flex ramp
transfer multiplied by the EIM whole footprint flex ramp shadow price.
Counterfactual Dispatch Cost
The counterfactual dispatch for an EIM BAA mimics the market operations without importing or
exporting through the EIM transfers. The counterfactual dispatch moves units inside the BAA to
meet the same real-time load imbalance as the EIM dispatch based on economic merit order
without considering transmission constraints. For PacifiCorp, the transfer limit between PACE
and PACW is enforced in the counterfactual dispatch.
Neglecting transmission constraints in a BAA tends to underestimate the EIM benefit. The
magnitude depends on how significant the congestion is. Severe congestion impacting EIM
benefits was not observed until October 2017, where transmission congestion happened
between the generation in Wyoming and PACE's load in PacifiCorp. The impact of this
congestion to the EIM benefit calculation can be demonstrated with the following example.
Assume in PACE, load increased 10 MW from the base schedule, generation decreased 100
MW from the base schedule, and PACE imported 110 MW in EIM. Note that energy is balanced
in PACE with 110 MW of transfer import replacing 100 MW of generation and serving 10 MW of
load above the base schedule. Assume the decremented generation cost is $20/MWh, and the
import cost is $120/MWh. From an economic standpoint, the EIM dispatched the resources out-
of-merit with high cost supply being incremented and low cost supply being decremented. If we
were to calculate the EIM benefit ignoring the congestion effect, the benefit will be negative. The
calculation is as follows:
EIM dispatch cost = -100 MW * $20 = —$2,000.
EIM transfer cost = 110 MW * $120 = $13,200.
Counterfactual dispatch cost = 10 MW * $20 = $200.
For simplicity, ignore flex ramp and GHG. The EIM benefit is calculated as $200 — (—
$2,000 + $13,200) = —$11,000.
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To better understand the root cause of the negative benefit, we break the calculated benefit into
two components: infeasible base schedule and infeasible counterfactual.
1. Infeasible base schedule: In the EIM, the imported $120 transfer replaced 100 MW of$20
internal generation, and produced a negative benefit equal to 100*($20-$120) = -$10,000. The
extra dispatch cost in EIM is not due to economics, but due to infeasible base schedules for
certain constraints, which forces the EIM to mitigate congestion, and incurs additional cost. For
this reason, we need to add the congestion management cost to the counterfactual dispatch
cost to reflect the need to perform the same congestion management dispatch as in the EIM. In
the example, we add $10,000 to the counterfactual dispatch cost.
2. Infeasible counterfactual: In the counterfactual, the merit order dispatch did not know that
dispatching up the $20 generation would overload the transmission, and produced a negative
benefit equal to 10*($20-$120) = -$1,000. The counterfactual should recognize the economic
$20 supply is subject to transmission congestion, and cannot be dispatched. Therefore, in the
counterfactual dispatch, for increased net load, we dispatch only supply offers with a bid price
>= the transfer LMP. For decreased net load, we dispatch down only supply offers with a bid
price <= the transfer LMP. In the example, the net load is 10 MW, so we only dispatch
resources that bid above $120, assume these supplies cost $125/MWh.
With these two enhancements, we revise the benefit calculation as follows:
EIM dispatch cost = -100 MW * $20 = —$2,000.
EIM transfer cost = 110 MW * $120 = $13,200.
Counterfactual dispatch cost = 10 MW * $125 + $10,000 = $11,250.
The new EIM benefit is calculated to be $11,250 — (—$2,000 + $13,200) = $50.
These enhancements only apply when we detect significant congestion indicated by the LMP
difference between the BA's ELAP and DGAP greater than a tolerance setting. Currently, the
tolerance is set to $5/MWh.
The counterfactual dispatch makes unit commitment decisions only for the ISO's short start
units. The unit commitment decisions are based on the generic three-part variable cost formula,
which has converted startup cost and no load cost into variable dispatch cost, so unit
commitment can be determined by the economic metric order of the three-part cost.
Prior to the 2016 Q4 report, we used the resources' RTD dispatching limits from the EIM in the
counterfactual. The EIM dispatching limits are 10-minute ramp limited in RTD, and they may be
overly constraining for the counterfactual theoretically. The counterfactual will replace the
transfers with internal dispatches, but it does not need to do it within 10-minute timeframe.
When EIM transfer volumes are moderate relative to the EIM dispatching range, this limitation
may not be a real problem, because the EIM dispatch range is mostly sufficient to replace the
transfers. As the EIM footprint increases, the transfer volume between BAAs also increases. We
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observed that some EIM transfers exceeded 1,000 MW frequently. The EIM dispatching range
started to show its limitation. In Q4 of 2016, we expanded the resources' dispatching range to
base schedule and FMM dispatching limits. From Q2 of 2017, we decided not to use EIM
calculated limits. Instead, the dispatching range is constructed based on the resource's
economic bid range in the following way:
a) Start with the resource's bid range [bid_MW_min, bid_MW_max]
b) Block the ancillary service provisions, so the new range is [bid_MW_min+reg_down,
bid_MW_max— reg_up—spin — nonspin]
c) If the resource is a wind or solar resource, limit its upper limit by the forecasted output,
so the new range is [bid_MW_min+reg_down, min(bid_MW_max— reg_up— spin —
nonspin, wind or solar forecast)]
In cases where a counterfactual dispatch does not have sufficient supply offers to meet net load
imbalance, we assign a penalty cost for procuring more energy. If the BA does not import from
EIM, we extend its last economic bid segment. If the BA imports from EIM, we compare its last
economic segment against the EIM LMP, and set the penalty price to the higher of the two. In
summary, the penalty price per MWh is
• The highest offer price from the BA if the BA does not import from EIM,
• Max (the highest offer price from the BA, the transfer LMP) if the BA imports from EIM.
An EIM BAA may restrict the pool of dispatchable units in the counterfactual dispatch if that the
BAA's practice prior to joining EIM was to balance real-time load from a limited pool.
ISO Counterfactual Dispatch
The ISO would need to meet load without EIM transfers in the counterfactual dispatch. The
counterfactual dispatch is constructed in the following way:
1. Calculate the ISO's net EIM transfer;
2. Economically dispatch resources from the ISO to replace the transfer
A. If the ISO is importing from the EIM,
a. Find the ISO's undispatched supply with the variable cost (bid and three-part
converted) greater than or equal to the reference transfer price;
b. Sort and stack the supply by the variable cost from low cost to high cost; and
c. Clear the supply stack from low cost to high cost up to the transfer megawatts
B. If the ISO is exporting to the EIM,
a. Find the ISO's dispatched supply with the variable cost (bid and three-part
converted) less than or equal to the reference FMM transfer price;
b. Sort and stack them by the variable cost from high cost to low cost; and
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c. Clear the supply stack from high cost to low cost up to the transfer megawatts
The reference transfer price for the ISO is the maximum price of the incoming transfer points if
the ISO is a net transfer importer, and the minimum price of the outgoing transfer points if the
ISO is a net transfer exporter in RTD. Undispatched supply at lower bid cost than the reference
price is dispatched out of merit when the ISO is importing transfer at the reference price.
Dispatched supply at higher bid cost than the reference price is also dispatched out of merit
when the ISO is exporting transfer at the reference price. The ISO has complex networks and
constraints that are modeled in the EIM but not in the counterfactual. For example, supplies can
be locally transmission constrained and undispatched in the EIM, which have available supply at
lower bid cost than the LMP of the rest of the ISO. They should remain undispatched in the
counterfactual even they have lower supply cost, because they are constrained by transmission.
In the ISO's counterfactual dispatch, we only consider supplies above the reference transfer
price to replace incoming transfer into the ISO, and thus preventing the transmission
constrained lower cost supply being dispatched. Vice versa for the supplies below the reference
transfer price to replace outgoing transfer. The counter factual dispatch (applies for whole EIM,
not just the ISO) was based on 5-minute dispatch capability, and the reference price is the RTD
price.
Counterfactual Dispatch
All EIM entities, with the exception of Pacificorp, have their counterfactual dispatch constructed
in the following way. We will use NVE as an example.
1. Calculate the real-time net load imbalance for NVE;
2. Economically dispatch resources from NVE on top of the base schedules to meet NVE's
net load imbalance
A. If the net load imbalance is positive,
a. Dispatch NV Energy's bid-in supply above base schedules;
b. Sort and stack them by the variable cost from low cost to high cost; and
c. Clear the supply stack from low cost to high cost up to the net load
imbalance.
B. If the net load imbalance is negative,
a. Dispatch NV Energy's bid-in supply below base schedules;
b. Sort and stack them by the variable cost from high cost to low cost; and
c. Clear the supply stack from high cost to low cost up to the net load
imbalance.
PacifiCorp Counterfactual Dispatch
PacifiCorp East BAA and PacifiCorp West BAA would need to meet demand without intra-hour
transfers between PacifiCorp and the ISO, but transfers could occur between PACE and PACW
in the counterfactual dispatch. The PacifiCorp counter factual dispatch will be constructed in the
following way:
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1. Calculate the real-time net load imbalance for each BAA;
2. Economically dispatch resources from PacifiCorp on top of the base schedules to meet
net PacifiCorp load imbalance without violating the transfer limitations between PACE
and PACW.
A. If the net load imbalance is positive,
a. Find PacifiCorp's bid-in supply above base schedules;
b. Sort and stack them by the variable cost from low cost to high cost; and
c. Clear the supply stack from low cost to high cost up to the net load imbalance
subject to the transfer limit between PACE and PACW
B. If the net load imbalance is negative,
a. Find PacifiCorp's bid-in supply below base schedules;
b. Sort and stack them by the variable cost from high cost to low cost; and
c. Clear the supply stack from high cost to low cost up to the net load imbalance
subject to the transfer limit between PACE and PACW
GHG Revenue
Greenhouse gas (GHG) revenue for a resource is equal to its GHG allocation MW times the
GHG price.
GHG Cost
GHG cost for a resource is equal to its GHG allocation MW times its GHG bid.
Example
This example illustrates how the EIM benefit is calculated.
The transfers out of the EIM optimization are listed in Table 1. Base scheduled transfers have
been excluded in the FMM transfers and RTD transfers.
From To FMM FMM RTD incremental RTD transfer Transfer
BAA BAA transfer transfer transfer price cost
price
PACE NEV 140 $26 .� 10 $25 $3,890
P
NEVP CISO 160 $26 20 $30 $4,760
PACE PAC 190 $26 10 $25 $5,190
W
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PACW CISO 110 $26 -10 $30 $2,560
Table 1. An example of BAA to BAA transfers and prices
Assume the EIM energy imbalance and prices are as follows. Every BAA is balanced with Gen
+ Transfer— Load = 0. Assume the EIM optimization results in $1 GHG price, which means the
ISO's LMP is $1 higher than the neighboring BAA (NEVP and PACW), because there is no
congestion going into the ISO in the example. In the table below, positive transfer MW means
the BAA is importing and negative transfer MW means it is exporting. Also, transfers in the table
are sum of the transfers occur in both the FMM and the RTD with base scheduled transfer being
excluded.
en Load Net transfer in MW LMP GHG price
CISO 0 280 280 $31
NEVP 50 20 -30 $30
$1
PACE 150 -200 -350 $20
PACW 100 200 100 $30
Table 2. EIM energy imbalance and prices by BAA for one 5-minute interval
Transfer Cost
The transfers occur in both FMM and RTD, and their volume and prices are listed in Table 3.
They are calculated from applying the convention that importing is positive and exporting is
negative the BAA to BAA transfers, and summing them over all the neighboring BAAs.
BAA transfer cost
CISO $7,320 = $4,760+$2,560
NEVP ($870) _ $3,890-$4,760
PACE ($9,080) _ -$3,890-$5,190
PACW $2,630 = $5,190-$2,560
Table 3. EIM transfer cost by BAA
For flex ramp, we calculate its transfer and transfer cost in Table 4.
BAA Direction Req. Award Allocation Flex ramp Flex Flex ramp
transfer in ramp transfer
price cost
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CISO upward 150 100 75 -25 $1 -$25
NEVP upward 10 0 5 5 $1 $5
PACE upward 20 0 10 10 $1 $10
PACW upward 20 0 10 10 $1 $10
CISO downward 0 0 0 0 $2 $0
NEVP downward 10 10 2 -8 $2 -$16
PACE downward 20 0 4 4 $2 $8
PACW downward 20 0 4 4 $2 $8
Table 4. Flex ramp transfer example
EIM Dispatch Cost
Now calculate the total bid cost associated with the EIM dispatches (delta from base
schedules). The EIM dispatch costs are listed in Table 5.
BAA Gen—EIM EIM dispatch cost
CISO 0 $0
NEVP 50 $1,450
PACE 150 $2,700
PACW 100 $2,800
Table 5. EIM dispatch cost by BAA
Counterfactual Dispatch Cost
Then construct the counterfactual dispatches as described in the previous section, and sum up
the counter factual dispatch cost for each BAA as shown in Table 6.
BAA Gen_CF Counterfactual dispatch cost
CISO 280 $9,240
NEVP 20 $640
PACE -200 ($3,800)
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PACW 200 $6,200
Table 6. Counterfactual dispatch cost by BAA
GHG Cost and Revenue
The GHG costs associated with the 280 MW of importing transfer into CISO, and the revenues
received by the GHG allocated MWs in both FMM and RTD are listed in Table 7.
BAA GHG FMM MW GHG RTD MW GHG cost GHG revenue
CISO 270 280 $0 -$280
NEVP 0 0 $0 $0
PACE 200 200 $20 $200
PACW 70 80 $75 $80
Table 7. GHG cost and revenue by BAA
EIM Benefit
With all the cost and revenue for each BAA available, we can use the formula EIM benefit for a
BAA = counterfactual dispatch cost— (EIM dispatch cost + transfer cost + flex ramp transfer
cost) + GHG revenue — GHG cost to calculate EIM benefit for each BAA. The results are shown
in Table 8.
BAA CF dispatch EIM dispatch Transfer Flex GHG GHG EIM
cost cost cost transf cost revenue benefit
er
cost
CISO $9,240 $0 $7,320 $0 $1,665
NEV $640 $1,450 $0 $0 $71
P
PAC ($3,800) $2,700 ($9,080) $18 $20 $200 $2,742
E
PAC $6,200 $2,800 $2,630 $18 $75 $80 $757
W
Table 8. EIM benefit for one 5-minute interval
This calculation is performed for each 5-minute interval with unit $/hr. We convert the $/hr
benefit into the dollar benefit by multiplying 1/12. Then the 5-minute interval benefits in dollar
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amount can be aggregated into the monthly benefit by summing all the 5-minute intervals in the
month.
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CONFIDENTIAL
AVISTA CORPORATION
STATE OF IDAHO
CASE NO. AVU-E-22-11
ANNUAL POWER COST ADJUSTMENT (PCA)
COMPLIANCE FILING
CONFIDENTIAL APPENDIX B
EIM BENEFITS EVALUATION FOR EIM CUSTOMERS
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EIM Benefits Evaluation
for EIM Customers
May 07, 2019
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Change log:
Date Change description Author
03/26/2018 Initial version of phase 1 design notes Ying Xiao
4/12/2018 Updated Logic to handle Configuration Change of MSG with overlapping ranges Ying Xiao
4/30/2018 Updated logic to calculate dispatch range and price used for extended segment in CF Ying Xiao
10/2/2018 Excluded renewable units from EIM dispatch costs calculation Ying Xiao
1/25/2019 Updated NLI and transfer benefit logic to handle base transfer Ying Xiao
3/25/2019 Added logic for PacifiCorp to handle the model with two BAAs; Ying Xiao
Added an option, CFDispatchwithCongestion Model,to allow to switch on/off the
congestion model.
05/07/2019 Included renewables in CF and EIM dispatch costs calculation Ying Xiao
Reference:
1. EIM Quarterly Benefit Report Methodology, https://www.westerneim.com/Documents/EIM_BenefitMethodology.pdf
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Table of Contents
1 Background ................................................................................................................................................................................................... 4
2 EIM Benefit Evaluation Methodology............................................................................................................................................................. 4
3 EIM Benefit Calculation Components............................................................................................................................................................. 4
3.1 EIM Dispatch Cost.................................................................................................................................................................................. 4
3.1.1 Examples of EIM Dispatch Cost Calculation in EIM Study ................................................................................................................ 5
3.2 CF Dispatch Cost .................................................................................................................................................................................... 5
3.2.1 Net Load Imbalance Calculation...................................................................................................................................................... 5
3.2.2 Detailed logic of CF dispatch........................................................................................................................................................... 7
3.2.3 Examples of CF Dispatch................................................................................................................................................................. 9
3.2.4 Detailed Logic of CF Dispatch with Heavy Congestion in BS............................................................................................................15
3.3 EIM Net Transfer Revenue.....................................................................................................................................................................10
3.3.1 Transfer Price calculation ..............................................................................................................................................................11
3.4 GHG Net Revenue.................................................................................................................................................................................13
3.5 FRP Net Revenue...................................................................................................................................................................................14
4 Appendix: Logic to handle Configuration Change of Multi-Stage Generators (MSG) ......................................................................................14
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1 Background
CAISO has published the general methodology for EIM benefits calculation (as seen in the reference of this document). The heuristic approach
allows to estimate EIM benefits without performing sophisticated optimization-based unit commitment and dispatch studies.
By using the same methodology described in the CAISO document in high-level,the goal of this design is to replicate CAISO benefit calculation
for EIM customers.
2 EIM Benefit Evaluation Methodology
For an EIM balancing authority area (BAA),the benefit can take the form of cost savings or profit or their combination[1]:
• Energy Cost Savings: BAA imports energy economically, or its base schedules (BS) are re-optimized by the EIM on an intra-hour basis.
• Energy Profit: BAA exports energy which are paid above the resource costs.
• Green House Gas (GHG) profit: BAA exports of GHG resources into California,that are paid the GHG price.
• Flexible Ramp Product(FRP) profit : BAA exports FRP and is paid at the FRP price (profit occurs when the FRP price is higher than the
opportunity cost of not providing FRP).
The EIM Benefits calculation, from a summarized level, is the following. It calculates the cost savings of the EIM's dispatch compared to what
would have occurred if there was no EIM dispatch (counterfactual dispatch).
EIM benefit=CF dispatch cost—EIM dispatch cost+EIM net transfer revenue+GHG net revenue+FRP net revenue
The following components of the EIM Benefits Calculation are performed at the 5-minute level.The results are then summed to the monthly-
level, which is the level at which the CAISO posts their EIM Benefits Calculation results.
3 EIM Benefit Calculation Components
3.1 EIM Dispatch Cost
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For participating resources (PR),the EIM dispatch cost is calculated as the EIM Dispatch from the base schedule (BS) in order to meet the net
load imbalance with the EIM Transfer.The EIM dispatch cost uses the resource's bid price.
For non-participating resources (NPR),their output may deviate from the BS too. With the assumption of consistent deviation behavior between
in EIM and not in EIM, the impacts should be the same to CF dispatch cost and EIM dispatch cost, that is,they cancel out each other. Therefore,
there is no need to add the costs in the terms.
The current CAISO rule is, if a unit in transition,the transition period will not be included in EIM dispatch cost calculation.The reason is, the cost
impact on EIM dispatch and CF are the same, so they wash-out.
For MSG with DOT and BS at different configurations, please refer to appendix "Logic to handle Configuration Change of Multi-Stage Generators
(MSG)".
3.1.1 Examples of EIM Dispatch Cost Calculation in EIM Study
In the table below, Inc MW stands for unit incremental dispatch above the BS, Dec MW for unit decremental dispatch below the BS.
Table 1. EIM Dispatch Cost Calculation
EIM Dispatch segment Bid price ($/MWh) Inc MW Dec MW Inc/Dec cost ($)
Unit 1, Segment 1 20 20 - 20*20/12= 33.4
Unit 2, Segment 2 30 - 10 - 10*30/12=- 25
3.2 CF Dispatch Cost
For a specific EIM customer,the CF study simulates the system operations without importing or exporting through the EIM transfers. Using
hourly BS as the baseline, it redispatches the resources to meet the real-time net load imbalance.
3.2.1 Net Load Imbalance Calculation
Conceptually, net load imbalance is the imbalance caused by:
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• Load forecast (LF) error: Deviation between the LF value used for T-40 BS submission and the LF for real time dispatch (RTD) market
clearing;
• Supply deviations caused by
0 outage/derate of units with BS; or
o dispatch of renewable resources away from the BS based on the actual output or curtailment.
Net load imbalance is calculated based on EIM RTD dispatch and EIM RTD transfer. In this design, the convention is, exporting transfer is positive
and importing transfer is negative.
Net load imbalance MW=Total RTD dispatch MW of PRs- Total BS MW of PRs -EIM RTD transfer MW
Here
EIM RTD transfer MW is the delta transfer MW dispatched by EIM on top of base transfer. It's calculated as:
RTD transfer MW—RTD Base transfer.
where
RTD transfer MW: overall transfer MW cleared in CAISO RT market;
RTD—Base—transfer: base transfer submitted by EIM customers.
Note: RTD transfer MW is the transfer result from CAISO; RTD—Base—transfer is the tagged transfer MW from EIM customers.
If a unit in transition, at transition period it's not included in net load imbalance calculation.
For MSG with DOT and BS at different configurations, please refer to appendix "Logic to handle Configuration Change of Multi-Stage Generators
(MSG)".
Table 2.1 Net Load Imbalance Calculation
Scenario Total RTD dispatch MW of PRs Total BS MW of PRs EIM transfer MW Net Load imbalance
1 2000 1500 50 (2000- 1500)-50= 450MW
2 2400 2500 -50 (2400-2500)- (-50)=-50MW
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The dispatch will be based on merit order of bid price to ensure minimum bid costs, with consideration of congestion as needed. Resource ramp
rate limit and Losses are ignored in the dispatch.
Currently, it's assumed by CAISO that there is no need to commit/decommit resources for load imbalance. The general logic for CF calculation is,
to stack up available capacity economically to meet load imbalance. Here available capacity includes all online resources in RTD and off line non-
MSG resources. For MSG resources, only the configuration dispatched by RTD shall be considered.The CF dispatch range is constructed based on
the resource's economic bid range in the following way:
a) Start with the resource's bid range [bid_MW_min, bid_MW_max], which should not exceed the economic dispatch range[Pmin, Pmax]
b) Block the ancillary service provisions, so the new range is [bid_MW_min+Reg_down, bid_MW_max—Reg_up—Spin]
c) If the resource is renewable resource, such as wind or solar resource, limit its upper limit by the forecasted output, so the new range is
[bid_MW_min+Reg_down, min(bid_MW_max—Reg_up—Spin, wind or solar forecast)]
If load imbalance cannot be satisfied using available capacity,the highest available bid (including both online and offline)will be extended as the
bid price to procure more supply. Here the highest available bid is identified among all the available resources,that is, not include off line
configuration of MSGs.
In cases CF does not have sufficient supply offers to meet net load imbalance, a pseudo price will be assigned to the extended segment for
procuring more energy.
o If the BA does not import from EIM in RTD, we extend its last economic bid segment. Here the import is net over all RTD transfers.
o If the BA imports from EIM, we compare its last economic segment against the EIM transfer price, and set the pseudo price to the higher
of the two.
In summary, the pseudo price per MWh is:
• the highest offer price from the BA if the BA does not import from EIM,
• max(the highest offer price from the BA, the EIM transfer price) if the BA imports from EIM.
Here, the EIM transfer price is a weighted average transfer revenue from imports.Taking EIM customer A as an example, with net import, A may
import from both CAISO and NVE, and export to PACE.The EIM transfer price can be calculated as:
abs (Transfer Revenue with CAISO+Transfer Revenue with NVE)/(RTD import MW from CAISO+RTD import MW from NVE)
3.2.2 Detailed logic of CF dispatch
Detailed steps for the CF dispatch and cost calculation are described in the below sections.
If a unit in transition, during the transition period, it's not eligible for CF dispatch.
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3.2.2.1 Detailed logic of CF dispatch for Non-PacifiCorp BAAs
1. For each 5-min interval, calculate the real-time net load imbalance based on the corresponding EIM case;
2. Based on the BS, re-dispatch non-outaged resources economically to meet the net load imbalance:
A. If the net load imbalance is positive,
a. Find resources' bid-in supply above BS.
b.The bid-in supply is sorted by the respective resources' bid price in ascending order.
c. Clear the bid-in supply from the lowest cost to the highest cost, until the net load is re-balanced.
B. If the net load imbalance is negative,
a. Find resources' bid-in supply below BS;
b. The bid-in supply is sorted by the respective resources' bid price in descending order.
c. Clear the bid-in supply from highest cost to lowest cost, until the net load is re-balanced.
3.2.2.2 Detailed logic of CF dispatch for PacifiCorp BAAs
With consideration of transfers between PACE and PACW in the counterfactual dispatch,the PacifiCorp counter factual dispatch will be
constructed using the below method:
1. For each 5-min interval, calculate the real-time net load imbalance for each BAA respectively, i.e., PACE BAA and PACW BAA, based on
the corresponding EIM case;
2. Based on the BS, re-dispatch non-outaged resources economically to meet the net load imbalance without violating the transfer
limitations between PACE and PACW:
A. If the net load imbalance is positive,
a. Find resources' bid-in supply above BS;
b. Sort the bid-in supply by the respective resources' bid price in ascending order;
c. Clear the supply stack from the lowest cost to the highest cost subject to the transfer limit between PACE and PACW, until the
net load is re-balanced.
B. If the net load imbalance is negative,
a. Find resources' bid-in supply below BS;
b. Sort the bid-in supply by the respective resources' bid price in descending order;
c. Clear the supply stack from the highest cost to the lowest cost subject to the transfer limit between PACE and PACW, until the
net load is re-balanced.
Here the transfer limit only considers export transfer limits on the HMWY tie from PACE to PACW,that is, in CF dispatch, only allow the
flow from PACE to PACW.The export transfer limits on the HMWY tie can be retrieved from the OASIS report "EIM Transfer Limits by
Tie".
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(For implementation, make sure the logic to cover at least the two scenarios below:
1. PACW sees positive net load imbalance, and PACE has cheaper available bid-in capacity, PACE resources are dispatched up, and
transfer to PACW to support PACW's power balance;
2. PACE sees negative net load imbalance, and PACW has more expensive available bid-in capacity to reduce, PACW resources are
dispatched down to support PACE's power balance with transfer from PACE to PACW)
3.2.3 Examples of CF Dispatch
There are four scenarios of CF Dispatch shown in below tables. The scenarios include: 1) a net load imbalance of 50 MW, 2) a net load
imbalance of 100 MW, 3) a net load imbalance of—50 MW, and a net load imbalance of—100 MW.
Inc stands for unit incremental dispatch above the BS, Dec for unit decremental dispatch below the BS. Unless the capacity is extended,
the Inc/Dec dispatch shall be within the range of[Pmin, Pmax] and with ancillary services (AS) MW being carved out. Since offline units
are considered in this dispatch, in addition to regulation and spinning reserve, we also need to consider non-spinning reserve MW as
well.
Table 3.1. Scenario 1: Ordered bid stack and bids clearing with net load imbalance 50MW
Available bid stack Bid price ($/Mwh) Available Inc MW Extended Inc MW Inc MW Inc cost ($)
Unit 1, Segment 2 20 20 - 20 400/12= 33.3
Unit 2, Segment 4 25 10 - 10 250/12=20.8
Unit 2, Segment 5 34 25 - 20 850/12=70.83
Unit 3, Segment 3 40 10 - 0 -
Table 3.2. Scenario 2: Ordered bid stack and bids clearing with net load imbalance 100 MW
Available bid stack Bid price ($/Mwh) Available Inc MW Extended Inc MW Inc MW Inc cost ($)
Unit 1, Segment 2 20 20 - 20 400/12= 33.3
Unit 2, Segment 4 25 10 - 10 250/12=20.8
Unit 2, Segment 5 34 25 - 25 850/12=70.8
Unit 3, Segment 3 40 10 45 45 1800/12=150
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Table 3.3. Scenario 3: Ordered bid stack and bids clearing with net load imbalance-50MW
Available bid stack Bid price ($/Mwh) Available Dec MW Extended Dec MW Dec MW Dec saving ($)
Unit 3, Segment 3 40 10 - 10 400/12= 33.3
Unit 2, Segment 5 34 25 - 25 850/12=70.8
Unit 2, Segment 4 25 20 - 15 375/12=31.25
Unit 1, Segment 2 20 20 - 0 -
Table 3.4. Scenario 4: Ordered bid stack and bids clearing with net load imbalance-10OMW
Available bid stack Bid price ($/Mwh) Available Dec MW Extended Dec MW Dec MW Dec saving ($)
Unit 3, Segment 3 40 10 - 10 400/12= 33.3
Unit 2, Segment 5 34 25 - 25 850/12=70.8
Unit 2, Segment 4 25 20 - 20 500/12=41.67
Unit 1, Segment 2 20 20 45 45 900/12= 75
13 AIM Net Transfer Revenue
The EIM net transfer revenue formula is (EIM export revenue- EIM import cost). For a BAA, EIM export revenue is the revenue of sales to other
BAAs.The EIM import cost is the cost of purchases from other BAAs.
Transfers may occur in both the fifteen-minute market (FMM) and the 5-minute markets (RTD). Transfers in the two markets at the same period
can be in opposite directions. For example, a BAA can import in the FMM and export in the RTD, or vice versa. In this design document,
exporting transfer is positive and importing transfer is negative.
In general, for a 5-minute interval, the transfer revenue of with each transfer counterparty can be calculated as:
Transfer Revenue—withCounterparty=EIM FMM transfer *FMM transfer price+(EIM RTD transfer—EIM FMM transfer) *RTD transfer price.
Here
EIM FMM transfer=FMM transfer—FMM base transfer;
EIM RTD transfer=RTD transfer—RTD base transfer.
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Due to tagging change, RTD base transfer can be different from FMM base transfer. This happened to IPC in the past months.
For EIM BAA A, it may transfer with multiple BAAs, say CAISO, NVE and PACE, as shown in below diagram.
The total net transfer revenue will be:
Transfer Revenue with CAISO+Transfer Revenue with NVE+Transfer Revenue with PACE
CAISO 0 0
r�
11kh— < \"l z
Figure 1. EIM BAA A direct interconnection with other EIM BAAs
3.3.1 Transfer Price calculation
Currently, if BAA A transfers with CAISO,A always collects the congestion rent; if counter party is not CAISO,A only collects half of the
congestion rent.The detailed calculation is described below.
If counter party is CAISO,then
Transfer price = if A exports,then
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LMP_ELAP_A+abs(transfer constraint shadow price)
Else if A imports,then
LMP_ELAP_A-abs(transfer constraint shadow price)
Endif;
Else (i.e., counter party is not CAISO)
Transfer price =0.5*( LMP_ELAP_A+ ELAP of Counterparty)
Endif.
Where
for ELAP of counterparty,taking transfer with NVE as an example,
If NVE is not locked out,then
ELAP of Counterparty= LMP_ELAP_NVE
Else (i.e., NVE got locked out due to failing sufficiency test)ELAP of Counterparty* (can be Magnolia's LMP)
endif
*As currently none of the EIM customers has access to other BAAs'failure information,for monthly EIM benefit evaluation of a specific month,
EIM customers will have to request a spreadsheet from CAISO with the HE, interval and adjustment to the counterparties' transfer price. Both
FMM and RTD adjustments are included.The PowerSettlements's benefit calculation tool needs to subtract the adjustment price from the CAISO
price to obtain the ELAP of Counterparty. (CAISO is working on a long-term solution to post the data on public GUIs.)
Table 7.1: Examples of Transfer Net Revenue Calculation between A and CAISO
FMM RTD
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Sce- MW LMP_ELAP Abs(Shadow Transfer price MW LMP_ELAP Abs(Shadow Transfer price Transfer net
nario _A price) ($/MWh) ($/MWh) _A price) ($/MWh) ($/MWh) revenue ($)
($/MWh) ($/MWh)
1 300 30 20 50 280 28 16 44 14,120/12=1176.67
2 300 30 20 50 -300 20 10 10 9,000/12=750
Table 7.2: Examples of Transfer Net Revenue Calculation
Sce- FMM RTD Transfer net
nario MW LMP_ELAP LMP_ELAP_A Transfer price MW LMP_ELAP LMP_ELAP_A Transfer price revenue ($)
_NVE ($/MWh) ($/MWh) _NVE ($/MWh) ($/MWh)
($/MWh) ($/MWh)
1 300 30 20 25 280 28 16 22 7,060/12=588.3
2 300 30 20 25 -300 20 50 35 -13,500/12=-1,125
'I A GHG Net RPVPn-
GHG net revenue is calculated as (GHG Revenue -GHG Cost).
For each 5-minute interval,the GHG revenue can be calculated as:
FMM GHG allocation MW*FMM GHG price+(RTD GHG allocation MW—FMM GHG allocation MW) *RTD GHG price.
For each 5-minute interval,the GHG cost can be calculated as:
RTD GHG allocation MW*GHG bid price.
Table 8: Examples of GHG Net Revenue Calculation
Sce- GHG bid price FMM RTD GHG revenue GHG cost GHG net
nario ($/MWh) GHG MW GHG price GHG MW GHG price ($) ($) revenue ($)
($/MWh) ($/MWh)
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1 0 180 5 220 6 1,140/12=95 0 95
2 8 100 6 120 5 700/12= 58.3 1 960/12=80 -31.7
3.5 FRP Net Revenue
FRP net revenue is calculated as (FRP revenue- FRP Cost). FRP revenue represents the payment received from other BAAs importing FRP
capacity from BAA A; FRP cost A's payment to other BAAs exporting FRP capacity to A.
In general,for a 5-minute interval,the FRP net revenue can be calculated as for FRP Up:
RTD FRP up export*RTD FRP up price+RTD FRP down export *RTD FRP down price
where
• RTD FRP export=A's total RTD FRP award—EIM area's RTD FRP award* (A's RTD FRP requirement/sum of each BAA's RTD FRP
requirement)
• RTD FRP price =A's RTD FRP price
The same calculation applies to FRP down as well.
4 Appendix I: Logic to handle Configuration Change of Multi-Stage Generators (MSG)
The current rules to handle configuration changes/commitment status changes in EIM benefit calculation are:
• If the BS of a MSG is in a different configuration from the current dispatch in RTD:
1. Reset BS using Pmin_current_config;
2. Net load imbalance will be calculated with the updated BS;
3. EIM dispatch cost and CF cost calculation will be based on the updated BS;
4. Current configuration's bid shall be treated as available for CF calculation (no change).
• If FMM commit a unit with zero BS:
1. Reset BS using Pmin;
2. Net load imbalance will be calculated with the updated BS;
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3. EIM dispatch cost and CF cost calculation will be based on the updated BS
If a unit is committed by CAISO, it's assumed to be online in CF as well.
5 Appendix II: Detailed Logic of CF Dispatch with Heavy Congestion in BS
This logic is controlled by an option, CFDispatchwithCongestion Model.The default value of this option is 0,that is,the logic is switched off in all
BAAs' EIM benefit evaluation.
5.1 Background
Neglecting transmission congestion within a BAA during BS calculation will lead to underestimate the EIM benefit.The impact can be explained
with the following example, as shown in Table 5.1.
In this example,the reason behind that EIM dispatched the resources out-of-merit with high cost import being incremented and low cost
internal generation being decremented is congestion. EIM dispatch considers impacts of congestion. If we were to calculate the CF dispatch cost
ignoring the congestion,the benefit would be inaccurate, sometimes even negative.The calculation is described in Table 5.1. For simplicity, flex
ramp and GHG terms are ignored in this example, and there is no consideration of 5 min granularity in the dispatch.
Table 5.1. EIM benefit with no congestion impacts
Actual Deviation/ Price EIM dispatch cost EIM transfer cost Counterfactual dispatch cost
EIM redispatch MW ($/MWh) ($) ($) ($)
Load +10 - 200 (=10 * $20 )
Generation -100 20 —2,000
Import 1 +110 120 1 13,200
EIM benefit calculated without considering congestion ($) 1 200—(-2,000+ 13,200) =—11,000
To better understand the root cause of the negative benefit,we break the cause into two components: infeasible BS and infeasible CF:
• Infeasible BS:
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In the EIM dispatch,the imported $120 transfer replaced 100 MW of$20 internal generation, and produced an extra cost of 100*($120-$20) _
$10,000.This extra cost is caused by infeasible BS.Therefore, this congestion management cost should also incur to the CF dispatch,to reflect
the need to perform the same congestion management dispatch as in the EIM.That is, in the example, $10,000 needs to be added to the CF cost
term.
• Infeasible CF:
The CF dispatch should recognize the economic$20 generation will cause transmission congestion,therefore cannot be dispatched.
o For increased net load,the CF can only dispatch up supply offers with a bid price>=the transfer price;
o For decreased net load, it can only dispatch down supply offers with a bid price<=the transfer price.
In the example,the CF can only dispatch resources that bid above$120 to meet the 10 MW net load. It's assumed that the next supply in the
offer stack costs$125/MWh.
Table 5.2. EIM benefit considering congestion impacts
Actual Deviation/ Price Supply Price>= EIM dispatch EIM transfer Counterfactual dispatch cost
EIM redispatch MW ($/MWh) Transfer price($/MWh) cost($) cost($) ($)
Load +10 - 100*(120-20)+ 10*125
Generation -100 20 —2,000
Import 1 +110 120 125 13,200
EIM benefit considering congestion ($) 11,250—(-2,000+ 13,200) = 50
5.2 CF Dispatch Cost Calculation Logic Considering Congestion Impacts
If significant congestion is detected, the below logic will be triggered to ensure congestion impacts to be considered in the CF study.The
situation is indicated by the LMP difference between the BAA's ELAP and DGAP greater than a tolerance setting. Currently,the tolerance is set to
$5/MWh in CAISO calculation.
If LMP ELAP- LMP DGAP >5 then
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CF dispatch cost= Infeasible BS cost+ Infeasible CF cost
Else
CF dispatch cost is calculated based on the logic described in section 3.2.2.
End if
Detailed logic to calculate Infeasible BS cost and Infeasible CF cost is:
For any RTD interval, if(total net RTD transfer is import)
and (Total RTD redispatch MW of PRs<Total BS of PRs) (i.e., RTD dispatches down PRs)
and exists(bid segment, RTD import price> bid price of EIM dispatched bid segment)then (i.e., import expensive MW to replace cheaper
internal resources)
Infeasible BS cost= if net load imbalance >0,then
[sum(BAA, Import MW*RTD import price) -Sum(bid segment, RTD dispatch down segment MW* segment bid price)]/12
else (i.e., net load imbalance<0)
[sum(BAA, Import MW*RTD import price) -Sum(bid segment, RTD dispatch down segment MW for BS infeasibility*
segment bid price)]/12
endif
Note:
1. For Infeasible BS cost calculation, only consider PRs.
2. Here BAA represents BAAs transfer with the studied BAA. Import MW should be positive.
3. For RTD import price, please refer to section 3.3 RTD transfer price calculation.
4. For a unit, RTD dispatch down MW= RTD dispatch MW—BS MW
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5. RTD dispatch down segment MW for BS infeasibility is RTD dispatch down segment MW capped by net transfer MW.
Infeasible CF cost= if net load imbalance >0,then
[sum(available bid segment I bid price >= max(BAA, RTD import price), CF dispatch segment MW* segment bid price)]/12
else (i.e., net load imbalance<0)
[sum(available bid segment I bid price<= min(BAA, RTD import price), CF dispatch segment MW* segment bid price)]/12
end if
End if
Note:
1. For Infeasible CF cost calculation, PRs should be included.
2. Here BAA represents BAAs transfer with the studied BAA.
3. For RT import price, please refer to section 3.3 RT transfer price calculation.
5.3 Examples of CF Cost Components Considering Congestion
Examples are constructed in this section to show how to implement the detailed logic described in the previous section.
• Scenario 1: Positive net load imbalance
Table 5.3. Scenario 1: Positive net load imbalance
Load Generation Import
From CAISO From NVE From PACE
Actual Deviation/EIM redispatch MW +10 -100 50 -10 (i.e., Export) 70
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RTD Price ($/MWh) - Please refer to table 5.2 1130 50 120
Table 5.4. Scenario 1: Bid segment dispatched down by EIM for BS infeasibility(Total =- 100MW)
bid stack dispatched down by EIM Bid price ($/MWh) Bid Segment(MW) Dec MW by EIM for BS infeasibility
Unit 1, Segment 2 20 50 30
Unit 2, Segment 4 60 30 30
Unit 2, Segment 5 70 40 40
Infeasible BS cost= [sum(BAA, ImportMW*RTD import price) -Sum(bid segment, RTD dispatch down segment MW* segment bid price)]/12
_ [50*130+70*120— (40*70+30*60+30*20)]/12
=808.33
Table 5.5. Scenario 1: Bid segments available for CF dispatch up
Available bid stack Bid price ($/MWh) Bid Segment(MW) Inc MW by CF
Unit 10, Segment 1 80 10 0
Unit 11, Segment 2 120 5 0
Unit 12, Segment 1 130 30 10
Infeasible CF cost= [sum(available bid segments bid price >= max(BAA, RTD import price), CF dispatch segment MW* segment bid price)]/12
= [10*130]/12
= 108.33
CF dispatch cost= Infeasible BS cost+ Infeasible CF cost= $916.66
• Scenario 2: Negative net load imbalance
Table 5.6. Scenario 2: Negative net load imbalance
Load Generation Import
From CAISO From NVE From PACE
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Actual Deviation/EIM redispatch MW -10 -100 30 -10 (i.e., Export) 70
RTD Price ($/MWh) - Please refer to table 6.2 130 50 120
Table 5.7. Scenario 2: Bid segment dispatched down by EIM for BS infeasibility (Total = - 90MW)
bid stack dispatched down by EIM Bid price ($/MWh) Bid Segment (MW) Dec MW by EIM for BS infeasibility
Unit 1, Segment 2 20 50 20
Unit 2, Segment 4 60 30 30
Unit 2, Segment 5 70 40 40
Infeasible BS cost= [sum(BAA, Import MW*RTD import price) -Sum(bid segment, RTD dispatch down segment MW for BS infeasibility*
segment bid price)]/12
_ [30*130+70*120— (40*70+30*60+20*20)]/12
= 608.33
Table 5.8. Scenario 2: Bid segments available for CF dispatch down
Available bid stack Bid price ($/MWh) Bid Segment (MW) Dec MW by CF
Unit 10, Segment 1 80 10 5
Unit 11, Segment 2 120 5 5
Unit 12, Segment 1 130 30 0
Infeasible CF cost= [sum(available bid segment I bid price<= min(BAA, RTD import price), CF dispatch segment MW* segment bid price)]/12
_ [5*120+5*80]/12
= 83.33
CF dispatch cost = Infeasible BS cost+ Infeasible CF cost= $691.67
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