businessrequirementsspecificationv10 · web viewwhen the iso enforces the gas nomogram...

Business Requirements Specification

Aliso CanyonDocument Version: 1

Date Created: 5/17/2016

Owner: Owens, Andrew Program Office

[ISO Department]Copyright 2012 California ISO

Doc ID: GNFDMDEHU6BB-46-53 of 25

Disclaimer

All information contained in this draft Business Requirements Specification (BRS) as provided by the California Independent System Operator Corporation (ISO) is prepared for discussion and information purposes only. The draft BRS is provided “as is” without representation or warranty of any kind, including, without limitation, a representation or warranty as to accuracy, completeness, or appropriateness for any particular purpose. The draft BRS shall be revised as the development and review of the business requirements progresses. The ISO assumes no responsibility for the consequences of any errors or omissions. The ISO may revise or withdraw all or part of this information at any time at its discretion without notice.




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Aliso Canyon Business Requirements Specification Date Created: 5/17/2016

Table of Contents1. PURPOSE ......................................................................................................................................................................................4

2. BUSINESS PROCESS IMPACTS................................................................................................................................................6

2.1 HIGH LEVEL DESCRIPTION OF BUSINESS PROCESS ....................................................................................................................6

2.2 VISUAL AIDES .............................................................................................................................................................................7

3. BUSINESS REQUIREMENTS.....................................................................................................................................................8

3.1 BUSINESS PROCESS: REBIDDING OF COMMITMENT COSTS..........................................................................................................8

3.1.1 Business Requirements......................................................................................................................................................8

3.2 BUSINESS PROCESS: GAS CONSTRAINT NOMOGRAM CHANGES................................................................................................10

3.2.1 Business Requirements....................................................................................................................................................10

3.3 BUSINESS PROCESS: INCREASE ACCESS TO INFORMATION PRIOR TO DAY-AHEAD (D+2 RUC SCHEDULE)............................17


3.4 BUSINESS PROCESS: RESERVE INTERNAL TRANSFER CAPABILITY............................................................................................18


3.5 BUSINESS PROCESS: REDUCE ANCILLARY SERVICE (AS) PROCUREMENT................................................................................18


3.6 BUSINESS PROCESS: DEEM SELECTED CONSTRAINTS UNCOMPETITIVE....................................................................................19


3.7 BUSINESS PROCESS: AFTER-THE-FACT COMMITMENT COST RECOVERY & PRICING IMPACTS................................................19


3.8 BUSINESS PROCESS: CLARIFICATION ON THE AUTHORITY TO SUSPEND VIRTUAL BIDDING....................................................20


3.9 BUSINESS PROCESS: ADJUSTMENT OF GAS PRICE INDEXES USED TO CALCULATE COMMITMENT AND DEFAULT ENERGY BIDS 21


3.10 BUSINESS PROCESS: ROUTINELY USE CURRENT GAS PRICE INFORMATION TO INCREASE EFFICIENCY OF ECONOMIC DISPATCH............................................................................................................................................................................................21

3.10.1 Business Requirements...............................................................................................................................................21

4. APPENDIX A...............................................................................................................................................................................25




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1. Purpose The purpose of this document is to capture and record a description of what the Users and Business Stakeholders of the project wish to obtain by providing high-level business requirements. This document establishes the basis for the agreement between the initiators and implementers of the project. The information in this document serves as input to determining the scope of projects and to all Business Process Modeling and System Requirements Specifications efforts.

Business requirements are what must be delivered to provide value for the Users and Business Stakeholders. Systems, software, and processes are the ways (how) to delivery, satisfy or meet the business requirements (what). The Initial BRS will provide sufficient information to determine the scope of the project and will provide the functional business requirements so that the Architecture Decision can be made. Following the Architecture Decision, the remaining non-functional business requirements, such as data, performance, web services, and security can be added to complete the Final BRS.

In October 2015, the Aliso Canyon natural gas storage facility in Southern California experienced a large gas leak significantly affecting gas markets and many of the people that live and work in the area. The facility is a key part of the gas system, serving gas customers in the Los Angeles Basin, including gas-fired power plants.

In response, the ISO is participating in an inter-agency task force with California Energy Commission (CEC), California Public Utility Commission (CPUC), Los Angeles Department of Water and Power (LADWP), and Southern California Gas (SoCalGas) to assess the risks of the limited operability of Aliso Canyon introduces to the gas and electric markets. Besides assessing these new reliability risks of gas curtailments or electric market load interruption measures, the task force is discussing possible mitigation measures.

On May 9, 2016, the CAISO filed for expedited approval of tariff revisions to improve its ability to maintain both gas and electric reliability in light of the risks to the CAISO controlled grid posed by the limited operability of the Aliso Canyon natural gas storage facility. Specifically, the CAISO requested authority to implement a series of tools it can use in its markets to mitigate operational risks that might lead to electric service interruptions on the CAISO electric grid due to restrictions of gas deliveries to electric generators. The CAISO is also proposing additional procedures to ensure generators have the opportunity to recover their fuel costs during the summer months when they are operating pursuant to a CAISO dispatch.

The CAISO requested that the Commission issue an order by June 1, 2016 that accepts most of the tariff revisions effective June 2, 2016 and accepts the balance of the tariff revisions effective July 6, 2016. If approved by the Commission, the requested tools will be available to the CAISO until November 30, 2016, unless the CAISO requests that the Commission permit them to be in effect beyond that time.

The CAISO requested the Commission grant the following authority:

1) To increase access to potentially useful market information prior to the CAISO day-ahead market, the CAISO proposes to provide scheduling coordinators, for informational purposes only, advisory commitment schedules produced in the residual unit commitment process conducted on a two-day-ahead basis and based on available bids and forecasts of system conditions. These advisory schedules are not financially or physically binding but should assist scheduling coordinators with gas procurement decisions and gas nominations processes.

2) Use timelier and more accurate gas commodity prices for commitment costs bid caps, default energy bids, and generated bids in the day-ahead market. This method will reflect prevailing gas prices, in contrast to the CAISO’s current day-ahead gas price index, which uses prices published the day before




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the market run. This will enable the day-ahead market to better capture gas price variability that may occur because of summer constraints, resulting in day-ahead schedules that are better aligned with actual gas system conditions.

3) Increase the gas commodity price used to calculate commitment costs and default energy bids for generators served by the affected gas systems by an amount necessary to ensure that the cost-minimizing market-clearing process considers the impact of gas system limitations in dispatching these generators, (e.g., the need to limit the dispatch of these generators for local rather than system-wide needs. This will help mitigate against the real-time market dispatching generators that are affected by the absence of available gas from Aliso Canyon and ensure that the CAISO dispatches do not further aggravate existing gas system constraints.

4) Allow a resource to rebid its resource commitment costs in the CAISO real-time market if the resource was not committed in the day-ahead market and the resource has not already started up and is within its minimum run time range.3 This can alleviate pressures on the gas and electric system by ensuring that generators’ costs in the CAISO real-time market appropriately reflect real-time gas constraints when conditions on the gas system change.

5) Ensure that the CAISO’s short-term unit commitment process does not commit resources in real-time that were not committed in the day-ahead and does not automatically resubmit bids into the real-time market. In addition to preventing the commitment of resources that have not bid into the real-time market and that have no obligation to do so, this tariff change will avoid exposing resources to any unplanned real-time gas procurement variability resulting from real-time commitments.

6) Include a new constraint in the CAISO markets that the CAISO operators can use to better ensure that dispatches are consistent with observed gas system limitations and avoid further stressing the gas system, which could in turn adversely impact electric grid reliability. Through this additional operational tool, the CAISO market clearing process will be able to limit the maximum amount of generation dispatched in a given area of the CAISO balancing authority area if burning more gas might risk jeopardizing gas and electric system reliability. Similarly, the CAISO can use the constraint to ensure that a minimum amount of generation is dispatched in a given area if necessary to avoid further stressing the gas system and assure reliability on the electric grid. This constraint will also allow CAISO operators to minimize variations between day-ahead and real-time gas usage if such variations have the potential to undermine gas and electric system reliability.

7) Expand the CAISO’s authority to reserve internal transfer capability by adjusting transmission constraints on the system and releasing such internal transfer capability as needed. The CAISO can use this operational tool in the market clearing process to help ensure that it dispatches or commits resources from other areas of the grid as necessary to ensure that resources in the southern California region are deployed in a manner that recognizes gas system limitations. In conjunction with authority to reserve internal transfer capability, the CAISO also requests authority to adjust the network model used in the release of monthly congestion revenue rights to ensure that the CAISO does not release rights that will not be sufficiently funded by congestion revenues collected in the day-ahead market.

8) Authorize the CAISO to suspend convergence bidding if the CAISO determines it is adversely affecting market efficiency. This authority is necessary so that virtual bidding does not undermine the measures taken by the CAISO to ensure that schedules and dispatches reflect actual physical conditions. This authority is also necessary to ensure, during the summer months when the system will be constrained and the CAISO is implementing the measures proposed in this filing, that virtual bidding does not result in adverse market outcomes that unfairly transfer revenue from one group of market participants to another.




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9) Add tariff provisions allowing scheduling coordinators to seek after-the-fact cost recovery from the Commission in a section 205 filing, to the extent they are otherwise unable to recover their costs through the CAISO’s cost recovery mechanisms.

2. Business Process Impacts2.1 High Level Description of Business Process

Process Description of Impact(s)Develop Infrastructure (DI) (80001) N/A

Develop Markets (DM) (80002) N/A

Manage Human Capabilities (MHC) (80003) N/A

Manage Market & Reliability Data & Modeling (MMR) (80004)

Level II - Manage Operations Planning

Need to develop a procedure for Operations Planning to detail out how to do the biasing. This may cause possible diagram changes.

Level II - Calculate & Monitor Energy Costs & Indices

Possible new process for determining Gas Risk Cost Commodity Adder to add to ECIC calculation.

Manage Markets & Grid (MMG) (80005)

Level II - Manage Real Time Market - Transmission & Electric System - Manage

Nomogram Updates

Add details to the level 3 and to the appropriate level 2s to capture a process to populate nomogram coefficient for SMDM (Allocate right/left max/min gas burn from combination regions to single regions, allocate DA daily limits to RT hourly limits, and assess competitiveness on this constraint and overwrite DCPA assessment on hourly.)

Level II - Manage Day Ahead Market See note above

Level II – Manage Real Time Hourly Market See note above

Manage Operations Support & Settlements (MOS) (80007)

Level II - Manage Good Faith Negotiation

Detail of the specific process for bid cost recovery needs to be developed. No change to Casewise diagram (Work already completed)

Plan & Manage Business (PMB) (80008) N/A




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Support Business Services (SBS) (80009) N/A

Support Customers & Stakeholders (SCS) (80010)

N/A




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2.2 Visual Aides

Tariff timeframe:




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3. Business RequirementsThe sections below describe the Business Processes and the associated Business Requirements involved in the project. These may represent high level functional, non-functional, reporting, and/or infrastructure requirements. These business requirements directly relate to the high level scope items determined for the project.

3.1 Business Process: Rebidding of Commitment Costs

3.1.1 Business Requirements

ID# Business FeatureRequirement Type

Potential Application(s)Impacted

AC-BRQ001

The ISO shall allow resources to rebid their commitment costs for hours in the real-time market unless it received a day-ahead schedule for those hours.

Core

Tariff

30.5.1(b)

SIBR

AC-BRQ002

The ISO shall implement in two phases where phase 1 shall include tariff rules detailing the eligibility for rebidding commitment costs in real-time and phase 2 which will fully automate validation rules that ensure within the market systems the commitment costs will not be accepted unless the criteria is met.

Core

Tariff

30.5.1(b)

SIBR




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AC-BRQ003

The ISO shall no longer automatically submit bids into the real-time market for resources that bid into the day-ahead market but did not receive a day-ahead schedule and that do not have a real-time must offer obligation.

Business Rule: This will ensure that the real-time market will not consider bids from generators that did not have an obligation to plan for gas procurement to operate in real-time from neither receiving a day-ahead schedule nor having a real-time must offer obligation.

Core

Tariff

34.6

40.6.3

SIBR




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3.2 Business Process: Gas Constraint Nomogram Changes




AC-BRQ004

The ISO shall implement a constraint in its day-ahead or real-time market, or both, that would limit the affected area gas burn to a gas burn limitation reflecting gas system limitations for either capacity reduction limitations or system imbalance limitations.

Core

BPM

Tariff 27.11

IFM/RTM

AC-BRQ005

The affected area, or the set of generators that included under the gas constraint(s), shall be the gas fired generation within the SoCalGas and SDG&E gas operating zone(s) identified by SoCalGas or SDG&E as under the maximum gas burn limitation. If the entire system is affected, the constraint would encompass the entire SoCalGas and SDG&E system.

Core

BPM

Tariff 27.11

IFM/RTM

AC-BRQ006

The ISO shall define a generation nomogram for each of the six gas operating zones under SoCalGas tariff. A seventh generation nomogram shall be defined to include all generators within the ISO’s portion of the SoCalGas and SDG&E system.

Core

BPM

Tariff 27.11

IFM/RTM




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AC-BRQ007

If the CAISO identifies or anticipates a gas system limitation that would impact more than one gas operating zone but not inclusive of the system-wide generation nomogram, the ISO shall allocate the multi-zone limitation to the individual gas operating zones.

Core

BPM

Tariff 27.11

IFM/RTM




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AC-BRQ008

System shall define the nomogram constraint using the following equation:

Equation 1: Gas Constraint(s)

LHSt ≤∑i∈S

αi (Gi ,t ) ≤ RHS t

S Set of generators in affected area (1 or more gas operating zones)

G Power output (MW)

∝i Energy (MW) to million cubic feet (MMcf) gas conversion factor (Masterfile heat rate value at given MW output * unit conversion factor)

LHSt Left hand side limit enforcing lower bound constraint, limit formulation described in Equation 3

RHS t Right hand side limit enforcing upper bound constraint, limit formulation described in Equation 2 and Equation 3 depending on the type of system limitation. [Equation 2 and 3 shall be described in the following BRQs].

Core

BPM

Tariff 27.11

IFM/RTM




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AC-BRQ009

System shall define hourly parameter(s) limiting affected area gas burn depending on whether it is a constraint or total/incremental gas burn.

If total gas burn limitation due to reduction in capacity or deliverability is defined by:

Equation 2: Gas Capacity Reduction Limitation

Where limit is set as follows :

RHS t=γ t Rh

∑1

N

γt=1

Rh Gas system limitation which could be a MMcf/day limitation on pipeline capacity as result of planned outages provided by the gas company (if not provided ISO will default to gas system design capacity) or an hourly value in MMcf provided by gas company generally in instance of curtailments

γ t Allowance distribution coefficients associated with upper bound limit that distributes a MMcf/day amount over the intervals of a trading day based on ratio of hourly load forecast to daily load forecast, if provided an hourly burn limit and not a daily limitation this value will be 1

Core

BPM

Tariff 27.11

IFM/RTM




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AC-BRQ009

(cont.)

If incremental gas burn limitation parameters are defined by:

Equation 3: Gas System Imbalance Limitation

Where limits are set as follows :

LHSt=β t [R l+∑i∈S

αi (Gi , t )]RHS t=γ t [Rh+∑

i∈Sα i (Gi , t )]

∑1

N

β t=∑1

N

γt=1

S Set of generators in affected area

G Day-ahead market schedule

∝i Energy (MW) to million cubic feet (MMcf) gas conversion factor (Masterfile heat rate value at given MW output * unit conversion factor)

Rl Daily lower bound deviation allowance relative to day-ahead market schedule

Rh Daily upper bound deviation allowance relative to day-ahead market schedule

β t Allowance distribution coefficients associated with upper bound limit that distributes a MMcf/day amount over the intervals of a trading day based

Core

BPM

Tariff 27.11

IFM/RTM




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AC-BRQ010

IFM/RTM and PCA Requirement and MAPP

When the ISO enforces the Gas Nomogram constraint and the constraint is binding, there is a potential in which the Generation resource level LMPs (lower) and Pnode level LMPs (higher) are different. In this particular case, the ISO does not want the impact of the Gas nomogram to spill into the CRR and Virtual bid settlement process. The ISO has two processes syncing the Resource and Pnode level LMPs after the engine run. One in IFM/RTM before the payload is published. The other, as part of the Sync logic (after the fact based on correction). Both of them shall have logic to exempt any generation resource included in the gas nomogram and its associated pricing node from the Price Sync process when the Gas nomogram is binding. This logic would apply per market and interval.

Core IFM/RTM

AC-BRQ011

The ISO shall increase the number of allowed variables for nomograms with purely generators to 150. For nomograms with transmission corridors or a mix of transmission corridors and generators, the limit is still 25. A validation shall be developed to enforce the limits described here.

Core IFM/RTM




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3.3 Business Process: Increase Access to Information Prior to Day-Ahead (D+2 RUC schedule)




AC-BRQ012

The ISO shall run a D+2 RUC run consistent with its current practice and will only use bids in the bid stack present at the time the process is run. The informational results are neither financially nor operationally binding.

Core

BPM

Tariff

6.5.2.2.3

CMRI

AC-BRQ013

Bids for the operating day must be submitted prior to 10 AM two days prior to the operating day to be included in the D+2 RUC run. These bids can be resubmitted and updated until 10 AM day-ahead.

Core

BPM

Tariff

6.5.2.2.3

CMRI

AC-BRQ014

System shall publish the RUC clearing results for D+2 in the same manner as we publish the RUC binding results for D+1.

Core IFM




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3.4 Business Process: Reserve Internal Transfer Capability




AC-BRQ015

The ISO shall establish the amount of transfer capability reserved each day based on the anticipated gas or electric conditions.

Tariff

27.5.6

BPM

N/A

AC-BRQ016

The ISO shall determine based on system conditions whether it is optimal to only manually release the transfer capability in real-time if the transfer capability is needed to deliver energy to Southern California or to routinely release it.

Tariff

27.5.6

BPM

N/A

3.5 Business Process: Reduce Ancillary Service (AS) Procurement




AC-BRQ017

The ISO shall have the ability to reduce the amount of AS procured from resources in southern California to ensure the ISO markets procure ancillary services that have access to sufficient fuel to respond to a contingency event if needed.

BPM N/A




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3.6 Business Process: Deem Selected Constraints Uncompetitive




AC-BRQ018

The ISO shall deem selected internal constraints uncompetitive for specific hours or days when the proposed constraint limiting the affected area’s gas burn in southern California is enforced in the ISO market processes.

Business Rule: The determination shall be based on whether or not the actual electric supply conditions may be uncompetitive during periods when the gas constraint is enforced.

Tariff

39.7.2.2

N/A

AC-BRQ019

System shall allow a manual way to modify the competitive versus non-competitive status of a constraint so that, once it is set, it will stay that way until is cleared regardless of what DCPA displays. This manual way overrides the DCPA result. This is to allow Path 26 to be identified as "non-competitive" in the event that the ISO always enforce the gas nomogram constraints.

Core

Tariff

39.7.2.2

TBD

3.7 Business Process: After-The-Fact Commitment Cost Recovery & Pricing Impacts





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AC-BRQ020

The ISO shall provide the opportunity for market participants to seek after-the-fact commitment cost recovery to include a cost recovery filing opportunity for incurred marginal procurement costs associated with providing incremental energy.

Tariff

30.11

39.7.1.1.3

40.6.8.1.7

N/A

AC-BRQ021

The ISO shall allocate costs the Commission finds to be just and reasonable similar to how it allocates costs associated with the resolution of good faith negotiations as specified in Section 11.14: awards payable by or to the CAISO that the CAISO is not able to allocate to or to collect from a Market Participant or Market Participants in accordance with Section 13.5.3. These charges will be allocated among Scheduling Coordinators over an interval determined by the CAISO and pro rata based on EIM Measured Demand during that interval, if the dispute concerned the Real-Time Market, or otherwise Measured Demand during that interval.

Core

Tariff

30.11

39.7.1.1.3

40.6.8.1.7

Settlements

3.8 Business Process: Clarification on the Authority to Suspend Virtual Bidding




AC-BRQ022

The ISO shall have the ability to suspend virtual bidding in the event that the ISO identifies market inefficiencies.

Tariff

7.9.2 (d)

N/A




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3.9 Business Process: Adjustment of Gas Price Indexes Used to Calculate Commitment and Default Energy Bids


As a short term means, the ISO shall have the flexibility to apply a scalar to the commodity price used to determine the gas price index for the SoCalGas and SDG&E generators to allow commitment cost offers and mitigated energy offers to better reflect both (1) the changed economics due to economic incentives associates with gas balancing imposed on generators and (2) intraday gas price variations relative to the gas price index.



AC-BRQ024

The real-time gas price index used in the Commitment Cost proxy cost and generated bid calculation shall be configurable but will initially be set to scale the gas commodity price to 175% of the gas commodity price. This shall only apply to SoCalGas and SDG&E.

Core

39.7.1.1.1.3 (d)

ECIC

AC-BRQ026

For the default energy bids used by the real-time market, the ISO shall increase the default energy bid by adjusting the gas price index used in its calculation. The gas price index used in the default energy bid calculation shall be configurable but will initially be set to scale the gas commodity price to 125% of the gas commodity price.

See Appendix A for the equations for this process.

Core

39.7.1.1.1.3 (d)

ECIC

3.10 Business Process: Routinely Use Current Gas Price Information to Increase Efficiency of Economic Dispatch





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AC-BRQ028

The ISO shall implement a next day index for gas drawn the morning on the day prior to its electric operating day between 8 AM and 9 AM PST for in that day’s day-ahead market.

Business Rule: The cutoff time from obtaining data from WEBICE shall be configurable but will be initially be set to 8:30 AM PST.

Core

BPM

Tariff

6.5.2.3.4

30.4.1.2

31.6.1

39.7.1.1.1.3 (a)(b)(c) and deleting old (b)

ECIC

AC-BRQ030

The ISO shall retire the manual price spike procedure.

Business Rule: The ISO will no longer be converting resources that elected the registered cost option to proxy cost option. To take advantage of the more granular daily prices, Scheduling Coordinators will need to elect proxy cost option.

Core

BPM

Tariff

6.5.2.3.4

30.4.1.2

31.6.1


ECIC

AC-BRQ031

The next day gas index would be used for calculating proxy commitment costs and default energy bids, and generated bids. The approximation would be made and used to determine the ISO’s cost estimates prior to the close of the day-ahead market at 10 AM PST.

Business Rule: This information shall not be posted to OASIS. Commodity trading hubs for resources participating in the day-ahead market.

Core

BPM

Tariff

6.5.2.3.4

30.4.1.2

31.6.1


ECIC




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AC-BRQ032

In the event that the ICE index fails to publish or WEBICE does not have the data, the ISO shall use the latest available next day gas index. This shall be calculated based on the tariff section 39.7.1.1.1.3 (c).

Core

BPM

Tariff

39.7.1.1.1.3 (c)

ECIC

AC-BRQ033

System shall publish the real time gas price index inclusive of the 175% commitment cost scalar adder.

Core

BPM

ECIC

AC-BRQ034

The Scalarcommitment shall not change daily or within the day. Its initial value will be posted in the Market Instruments BPM as well as a description of the process the ISO will follow to adjust the ScalarCommitment. The process will result in a market notice being sent that notifies the market participants of a change and the effective ScalarCommitment value as of the notice date.

Business Rule: The process includes internal discussions, internal task force providing senior executives with a recommendation and senior executives approving any adjustments. After that, the ISO will release the above reference market notice and apply the change in its systems. This is a relative static process.

Core

BPM

N/A




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4. Appendix AThe GPI formulation just for the SCE and SDGE fuel regions. There will be scalars applied to the commodity price (relevant next day gas index) to get to a different GPI for energy versus commitment cost estimates. Every other fuel region will remain unaffected and the gas price indices are the same for commitment costs and default energy bid calculation (i.e. GPICommitment=GPI Energy). These scalars would be used to formulate the two different GPIs for the SoCalGas and SDG&E fuel regions every day. If adjusted up or down there would be a market notice specifying the new scalars.

Equation 4: GPI Formulation

GPICommitment=(Commodity Price∗ScalarCommitment )+Transportation Rate

GPI Energy=(Commodity Price∗ScalarDEB )+Transportation Rate

Where :

ScalarCommitment=1.75, Fuel Region is eligible for scalarScalarDEB=1.25, Fuel Region is eligible for scalarIn the following cost estimate equations, the ISO highlights the portion of the calculations affected and clarifies which

GPI is used for which cost estimate.1

Equation 5: Proxy Start-Up Costs

Start-up Cost={Start-up Fuel Cost+Start-up Energy Cost+GMC Adder , GH GCOMPLIANCE¿' N '∧MMA=0

Start-up Fuel Cost+Start-up Energy Cost+GMC Adder+GHG Cost ,GH GCOMPLIANCE ¿' Y '∧MMA=0Start-up Fuel Cost+Start-up Energy Cost+GMC Adder+GHG Cost+MMA ,GH GCOMPLIANCE¿

' Y '∧MMA ≠ 0

Where :

Start-up Fuel Cost=STRT ¿∗GPICommitmentStart-up Energy Cost=STRT ¿∗EPI

GMC Adder = Pmin * ( STARTUP¿/60 min )∗GMC

2GHG Cost = STRT ¿* Emissions Rate * GHG Allowance Rate

Equation 6: Proxy Minimum Load Costs

1 The equation for transition costs is not included but the GPICommitment would be used to determine the proxy transition cost estimate. Further, the GPICommitment




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Minimum Load Cost={Minimum Load Fuel Cost+VOM+GMC Adder , GH GCOMPLIANCE¿' N '∧MMA=0

Minimum Load Fuel Cost+VOM+GMC Adder+GHG Cost ,GH GCOMPLIANCE¿' Y '∧MMA=0

Minimum Load Fuel Cost+VOM+GMC Adder+GHG Cost+MMA , GH GCOMPLIANCE¿' Y '∧MMA≠ 0

Where :Minimum Load Fuel Cost=Unit Conversion∗Heat_Rate∗Pmin∗GPICommitment

VOM=VOM∗PminGMC Adder = Pmin * GMC

GHG Cost = Unit Conversion∗Heat_Rate∗Pmin* Emissions Rate * GHG Allowance Rate

Equation 7: Default Energy Bid Costs

Default Energy Bid Cost={(Segment's Fuel Cost+VOM+GMC Adder) * Scalar ,GH GCOMPLIANCE¿' N '∧DEBA=0

(Segment's Fuel Cost+VOM+GMC Adder+GHG Cost¿

∗Scalar , GH GCOMPLIANCE¿' Y '∧DEBA=0¿(Segment's Fuel Cost+VOM+GMC Adder+GHG Cost+ DEBA¿¿ Scalar , GH GCOMPLIANCE¿

' Y '∧DEBA ≠ 0¿

Where :

Individual Segment's Fuel Cost=Unit Conversion∗Heat_Rate∗GPIEnergy

GHG Cost = Unit Conversion∗Heat_Rate∗Emissions Rate * GHG Allowance Rate

Scalar=1.1




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