Helping our members work together toHelping our members ... conference... · Helping our members...
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SPP Mission
Helping our members work together toHelping our members work together to keep the lights on – today and in the future.
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The SPP Difference
• Relationship - Based
• Member - Driven
• Independence Through Diversity
• Evolutionary vs. Revolutionary
• Reliability and Economics Inseparable• Reliability and Economics Inseparable
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Members in nine states:
Arkansas Mississippi New MexicoArkansas
Kansas
Mississippi
Missouri
New Mexico
Oklahoma
Louisiana Nebraska Texas
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SPP Governing Documents
• Articles of Incorporation• Articles of Incorporation• Bylaws
M b hi A t• Membership Agreement• Criteria• Open Access Transmission Tariff (OATT)• Business Practices
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Process for New Member Interest• SPP Strategic Planning Committee (SPC) responsible for
id SPP ff f b iguidance to SPP staff for new member interest
• Process triggered on interest of party
SPP staff informs SPC Chair
SPP staff provides updates to SPC
SPC d t i d f M b hi F t i t SPP t ffSPC determine need for Membership Forum to assist SPP staff
• SPP staff provides updates to SPP Markets and Operations Policy Committee y
• Any recommendations or changes presented by SPP staff to SPP organizational groups
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• SPP staff to inform membership of all membership changes9
Overview of New Member On Boarding ProcessOverview of New Member On-Boarding Process• Initial Interest—education and conceptual analysis
Letter of Intent / Memorand m of Understanding• Letter of Intent / Memorandum of Understanding
• Steps
Analysis and designAnalysis and design
Development
Regulatory and Legal
Training
IT
• Execution of Membership Agreement
• Testing / Implementation
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• Cutover / Post-Implementation10
Representative Project Schedule for New TORepresentative Project Schedule for New TOYear #2
Months Prior #1 #2 #3 #4 #5 #6 #7 #8 #9 #10 #11 #12 #13Year #1
Education and AnalysisInterested Party Negotiation Cost Allocation Implications Transmission Planning Implications Review with SPC Appointed GroupLetter of Intent/Memorandum of UnderstandingProject StartKi k ff d O i t ti Kickoff and Orientation
Analysis and Design New MPs Submit Requested Data SPP Functions ‐ Reliability, Market, Tariff Admin, Transmission Planning, Transmission Policy, Training, Settlements, and ITRegulatory NERC and RE Implications Regulatory, NERC, and RE Implications
Development SPP Development for Changes MPs and TO DevelopmentRegulatory and Legal FERC Filing State Filing(s)NERC Process NERC Process
SEAMS Agreement RevisionsTrainingMembership Agreement ExecutionTesting MPs and TO Readiness Testing Integrated TestingImplementation
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pCutoverPost‐ImplementationProject Ends
Regulatory Environment - Federal• Incorporated in Arkansas as a 501(c)(6)
fi inon-profit corporation
• FERC - Federal Energy Regulatory CommissionRegulated public utility
Regional Transmission Organization
• NERC - North American Electric Reliability Corporation
Founding member
Regional Entity
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Regional State Committee (RSC)
• Retail regulatory commissioners:g y
Arkansas Missouri OklahomaKansas Nebraska Texas
Louisiana maintains active observer status
Kansas Nebraska TexasMississippi New Mexico
• Responsibilities:
Cost allocation
Ensure adequate supply
Market cost/benefit analyses
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y
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R l t I t ti f N M bRegulatory Integration of a New Member
• Regional State Committee• Regional State Committee
Inclusion of representatives from new retail regulatory entitiesentities
Possible Bylaws revisions if there are unique circumstances; i.e., Nebraska Power Review Board d t t t il t tdoes not set retail customer rates
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Regulatory Integration of a New Member
• FERC• FERC
Application for permission to join SPP
SPP id t d l t d t d l i• SPP provides support and relevant data and analysis on costs and benefits
When SPP adds the new member’s Annual Transmission Revenue Requirement to the SPP Tariff, it files that information with FERC
Bylaws revisions, if needed, to allow for RSCBylaws revisions, if needed, to allow for RSC membership of a non-state regulatory entity
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Regulatory Integration of a New Member
• State Jurisdictions• State Jurisdictions
Applications, where required, for permission to join SPP and participate in SPP marketsand participate in SPP markets
• SPP provides support and relevant data and analysis on costs and benefits
• SPP provides background and education sessions to assist Commissioners, staff and the new member
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C li E f t d Compliance Enforcement and Standards Setting
• The SPP Regional Entity (RE) enforces compliance with federal NERC reliability standardsstandards
• Creates regional reliability standards ith t k h ld i twith stakeholder input
• Provides training and education to users, d t f b lk idowners, and operators of bulk power grid
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G d b h i d d
SPP Regional Entity
• Governed by three independent trustees• General Manager and RE direct staff
ContractorsSPP, Inc. and RE share staff for data collection and technical studies
• SPP, Inc. provides overhead functions (e.g. IT, HR, Accounting)
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NERC Compliance Registration
• SPP is a Regional Entity responsible for S g y pmonitoring compliance and enforcing NERC reliability standards
• SPP RE has a geographic footprint approved by NERC and FERC
• SPP RE is funded by a FERC-approved assessment to the Load Serving Entities in its f t i tfootprint
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C li R i t tiCompliance Registration• New Entity:
o A new entity located within the SPP RE footprint completes an SPP RE registration form listing its NERC functionsNERC functions
o SPP RE will process the entity registration
• Transferring Entity:• Transferring Entity:
o Entity may request transfer approval from NERC
o Current and proposed Regional Entities provide background information to NERC
o NERC approves or denies request
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o NERC approves or denies request
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What is Integrated Transmission Planning?
• Goal: Design transmission backbone to connect load to most reasonable generation alternatives
What is Integrated Transmission Planning?
most reasonable generation alternatives
Strengthen ties to Eastern and Western Interconnections
Improve connections between SPP’s east and west regionsImprove connections between SPP’s east and west regions
• Horizons: 20, 10, and Near Term
F R i l i t t d ith l l• Focus: Regional, integrated with local
• Resulting in: Comprehensive list of needed projects for SPP region over next 20 yearsneeded projects for SPP region over next 20 years
With 40 year financial/economic analysis
U d l i V l R li bilit d E i i bl
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• Underlying Value: Reliability and Economics are inseparable
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Why expand the transmission system?Why expand the transmission system?M
ore
SPP Today
Expand Transmission
Minimum for Reliable Delivery to Customers
ent
More Transmission
Needed
In
vest
me
s
C t E C t
SPP.org 2626Less Amount of Transmission MoreLe
ss Customer Energy Cost
ITP OverviewITP Overview• 20 Year
Develop a versatile and cost-effective EHV backbone with 300 kV and above solutions for a 20 year horizon
10 Y• 10 Year
Identify 100 kV and above solutions to issues not resolved in 20 Year Assessmentresolved in 20-Year Assessment
• Near-Term
Mitigate near-term, local reliability issues not addressed by 20 or 10 year assessments
Land Use Policy Task Force land use corridors natural
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Land Use Policy Task Force-land use corridors, natural resource stewardship, responsible land use, etc
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Incorporating New Members
• A potential new member’s existing facilities p gmust meet SPP reliability standards
• Potential members would be treated the samePotential members would be treated the same as an SPP member in studies
• Upgrades would be determined as if theUpgrades would be determined as if the potential member’s facilities are integrated into the SPP Tariff
• Possible reworking of 20-year and/or 10-year ITP
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Who pays for transmission?
TypeReliability Economic Sponsored Highway/
Who pays for transmission?
Type
“Base Plan Funding” “Balanced Portfolio” Byway
Funded 33% / 67% Postage Stamp Directly assigned w/ revenue credits
Postage Stamp
ReasonCriteria or
Designated Resource
Benefits / Cost ≥ 1 Sponsor(s) nominate projects
EHV projects from ITP
Voltage Transmission 345 kV and above
Effective 2005 2008 2009 6/19/2010
Highway/BywayVoltage Paid for by Region Paid for by Local Zone
300 kV and above 100% 0%above 100 kV and below 300 kV 33% 67%
Highway/Byway
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100 kV and below 0% 100%
O ti F tiOperations Functions
• Reliability Coordination (RC)y C ( C)
• Tariff Administration (TA)
• Interchange Coordination (IC)
• Market Operations (MO)
• Reserve Sharing Group (RSG)
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Relative Illustration of Operations Efforts(by Function)
Data Int Modeling App Dev Certification
Seams Coord Testing Training
RSG
MO
IC
RC
TA
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RC
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Reliability Coordination EffortsReliability Coordination Efforts• Data Integration
Acquire and map necessary real-time data
Add asset characteristics to applicable databases
• ModelingEnergy Management System (EMS)
NERC Interchange Distribution Calculator system
Operational planning models
• Application DevelopmentAdd displays
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Tool enhancements
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Reliability Coordination Efforts
• Certification
NERC on-site assessment
Preparation
• Seams Coordination
Negotiation of RC-RC agreement with new neighboring RCs
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Tariff Administration EffortsTariff Administration Efforts• Data Integration
Add OASIS i f ti (d li / i t i tAdd necessary OASIS information (delivery/receipt points, sources/sinks, pricing data, etc.)
Post existing transmission service rights
• ModelingData necessary to calculate AFCsy
Flowgate modeling
• Seams CoordinationSeams CoordinationEstablish agreements with new neighboring Transmission Providers
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AFC coordination with existing neighbors
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I t h C di ti Eff tInterchange Coordination Efforts
• Data Integration
Establish new entity relationships in application databases
• Application Development
Make necessary software changes in scheduling y g gapplications
• Seams Coordination
Develop coordination processes with new neighboring Balancing Authorities
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Market Operations EffortsMarket Operations Efforts• Data Integration
F ilit t t i t ti ith k t ti i tFacilitate asset registration with new market participants
Load forecast training
• Modeling
Model asset characteristics and owner relationships in market/commercial systemsmarket/commercial systems
• Application Development
Add displays
• Seams Coordination
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Calculate and verify market flow values40
R Sh i Eff tReserve Sharing Efforts
• Data Integrationg
Add asset characteristics and ownerships to applicable databases
• Application Development
Make necessary software changes in reserve sharingMake necessary software changes in reserve sharing applications
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Seams Agreement Components• Reliability Coordinator
Data Exchange
Operations Coordination Activities
Emergency ProceduresEmergency Procedures
• Transmission ProviderData Exchange
Transmission Service Coordination
Joint/Collaborative Planning
Cost AllocationCost ocat o
• Market OperatorMarket Flow Calculation
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Market-to-Market Congestion Management
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Seams Agreement Status
Reliability Transmission MarketReliability Coordinator
Transmission Provider
MarketOperator Notes
AECI N/A N/A Does not include CMP
CLECOCLECO N/A N/A
Entergy N/A Does not include CMP
MISOHave not begun market-to-
MISO market
WAPA N/A N/A Progress Started on TP-TP
TVA N/A N/ASome TP coordination exists through CMPTVA N/A N/A through CMP
ERCOT N/A N/A
WECC N/A N/A
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Comprehensive Some Elements Missing Update Needed Just Started
SPP Information Technology Efforts
• Reliability Coordination
E I b l M k t• Energy Imbalance Market
• Customer Registration / Settlements
• Interchange Scheduling
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IT High Level Functional DiagramETS
IT High Level Functional Diagram
Reserve Sharing
Scheduling System
TransSettlements
OASISSharing System
System (RTO_SS)
Market Settlements
Electronic Tagging System
LoadForecasting
Energy Imbalance Market System Energy Management
System (EMS)
Constraint
Curtailment Adjustment
Tool
ICCPManager
OPS1
Portal SiebelOffer Cap System
Load & Capability
Outage Coord
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Coord
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Reliability CoordinationETS
Reliability Coordination
Reserve Sharing
Scheduling System
Trans Settlements
OASISSharing System
System (RTO_SS)
Market Settlements
Electronic Tagging System
LoadForecasting
Energy Imbalance Market System Energy Management
System (EMS)
Constraint
Curtailment Adjustment
Tool
ICCPManager
OPS1
Portal SiebelOffer Cap System
Load & Capability
Outage Coord
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Coord
Reliability Coordination• Add entity to short-term and mid-term
load forecast systemsy• Add entity’s weather data• Add entity’s historical load data to EMS• Loaded updated EMS models
LoadForecastingEnergy Management
System (EMS)
• Establish ICCP links / verify data exchange
• Model new entity’s generation and t i i t i f ti ICCPtransmission outage information
• Configure load and capability system with appropriate entity data
• Add entity to NERC’s Security DataOPS1
Add entity to NERC s Security Data Exchange
Load & Capability
Outage Coord
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Coord
EIS MarketETS
EIS Market
Reserve Sharing
Scheduling System
Trans Settlements
OASISSharing System
System (RTO_SS)
Market Settlements
Electronic Tagging System
LoadForecasting
Energy Imbalance Market System Energy Management
System (EMS)
Constraint
Curtailment Adjustment
Tool
ICCPManager
OPS1
Portal SiebelOffer Cap System
Load & Capability
Outage Coord
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Coord
EIS Market • Update market system models with entity’s asset information
• Establish data exchange with gentity for resource plans, Deployment instructions, offer curves, bids, etcC d t t i k t
Energy Imbalance Market System
Constraint
• Conduct extensive market testing and trials
• Provide IT-centric market training
Managertraining
Offer Cap System
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Registration / SettlementsETS
Registration / Settlements
Reserve Sharing
Scheduling System
Trans Settlements
OASISSharing System
System (RTO_SS)
Market Settlements
Electronic Tagging System
LoadForecasting
Energy Imbalance Market System Energy Management
System (EMS)
Constraint
Curtailment Adjustment
Tool
ICCPManager
OPS1
Portal SiebelOffer Cap System
Load & Capability
Outage Coord
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Coord
Registration / SettlementsETS
Registration / SettlementsTrans
Settlements
Market Settlements
• Develop / deploy commercial model with entity registration data
• Establish connectivity to SPP’s Portal and other certificate based systemsother certificate based systems.
• Managed security / access needs• Support settlements testing and training
Portal Siebel
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Interchange SchedulingETS
Interchange Scheduling
Reserve Sharing
Scheduling System
Trans Settlements
OASISSharing System
System (RTO_SS)
Market Settlements
Electronic Tagging System
LoadForecasting
Energy Imbalance Market System Energy Management
System (EMS)
Constraint
Curtailment Adjustment
Tool
ICCPManager
OPS1
Portal SiebelOffer Cap System
Load & Capability
Outage Coord
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Coord
Interchange SchedulingReserve Sharing
Scheduling SystemSharing
SystemSystem
(RTO_SS) • Model new entity in reserve sharing system and update allocation methodology
Electronic Tagging System
• Update RTOSS to reflect new entity and applicable customizations
• Update TSIN for Electronic Tagging System
Curtailment Adjustment
Tool
System• Establish data exchange for energy
accounting and shadow settlements• Conduct significant RSS and RTOSS g
testing and training
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IT Implementation Plan*• Analysis and Design – 6 weeks• Construction – 6 weeks• Testing / Training – 4 months
• Support comprehensive training sessions• Perform regression testing / performance testing• Perform connectivity testing• Perform data exchange verification• Conduct parallel operations• Promote enhancements / models through all environments
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* Based on Implementation of Nebraska Entities
SPP On Boarding: Training ProcessSPP On-Boarding: Training Process
Project I iti ti
Analyze Design/DevelopmentInitiation
• Project plan includes Training
• SPP and Entergy analyze and assess training
• Design customized curriculum to meet identified needsTraining
timeline
• Training plan
assess training and performance support needs and audiences
identified needs
• Use and customize existing g p
development begins • Includes review of
services already in use by Entergy
curriculum where appropriate
• Develop new(e.g. Reserve Sharing, Tariff)
Develop new curriculum as needed
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SPP On Boarding: Training ProcessSPP On-Boarding: Training ProcessDeliverSchedule Evaluate
• Net conference and face-to-face
C i t d i
• SPP and Entergy decide schedule
• Evaluation levels:
T i i• Communicated via SPP Learning Center
• Materials available
• Multiple 2-3 hour sessions focused on different topics
Training program
Individualprior to sessions
• Supplemental materials available
different topics or tasks
• Repeated
Individual sessions
Readiness for integrationmaterials available
• Delivery designed to optimize retention
psessions to accommodate shift schedules
integration
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SPP On-Boarding: Functional Areas & Tasks
• Reliability *• Reliability *
Includes Reserve Sharing Group (RSG) **
• Tariff *
• Scheduling *g
• Settlements – Transmission *
S ( S)• Energy Imbalance Service (EIS) Market
• Settlements - Market
SPP.org 61* denotes areas where Entergy currently has some participation
SPP Regional Continuing EducationSPP Regional Continuing Education• SPP offers continuing education for operations personnel
at SPP and throughout regiong g
• In 2009, SPP awarded ~17,000 continuing education hours to 444 operators from 30 member or customer organizations
Summary of SPP Training and Performance
• On-boarding training and performance support customized
Support Offerings
• On-boarding training and performance support customized to Entergy’s specific needs
• Ad-hoc “just-in-time” training on additions or changes to
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j g gSPP’s services and systems
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Wh t ki d f k t d SPP h ?What kind of markets does SPP have now?• Transmission: Participants buy and sell use of
i l t i i li th t d bregional transmission lines that are owned by different parties
E I b l S i (EIS) P ti i t b• Energy Imbalance Service (EIS): Participants buy and sell wholesale electricity in real-time
Market uses least expensive energy from regional resourcesMarket uses least expensive energy from regional resources to serve demand (load) first
Sometimes it’s less expensive for a market participant to purchase power from another provider than to generate
SPP monitors resource/load balance to ensure system reliability
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What type of new markets is SPP implementing?What type of new markets is SPP implementing?
• Day Ahead: SPP determines what generating i h ld h d f iunits should run the next day for maximum
cost-effectiveness
• Operating Reserves: Market to buy and sell reserve energy that:
Meets emergency needs
Regulates instantaneous load and generation changes
Maintain electricity quality (keeping voltage up, etc.)
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Why develop new markets?• SPP conducts complex cost-benefit studies
before beginning any new market development
Under Regional State Committee oversight
2005 Charles River Associates analysis of the EIS market:
1. Estimated benefit of $86 million for first year
2. Actual benefit of $103 million for first year
N k t ill b i ti t d• New markets will bring estimated average additional net benefits of $100 million
A di t 2009 V t l i
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According to 2009 Ventyx analysis
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Understanding Reliability Unit Commitment
Generation
Bid in Load and Operating Reserve cleared in DA Market
Generation committed in RUC
gaw
atts
cleared in DA MarketSPP Load Forecast and
Operating Reserve Requirements (RUC Input)
Meg
S lf C itt d R
Generation de-committed in RUC
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Self Committed Resources
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Hour1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Benefits of Operating Reserves MarketBenefits of Operating Reserves Market• Greater access to reserve electricity
• Improve regional balancing of supply and demand
• Facilitate integration of renewable resourcesg
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Future Energy and Operating Reserve Market FunctionsFuture Energy and Operating Reserve Market FunctionsDA Market Offers (Energy and Operating Reserve), Bids, Operating Reserve
Requirements
RTBM Offers, Load Forecast, Operating
Reserve Requirements
RTBM Offers, Load Forecast, Operating
Reserve Requirements
DA Market Offers (Energy and Operating Bids, Operating Reserve
Requirements
RTBM Offers, Load Forecast, Operating
Reserve Requirements
RTBM Offers, Load Forecast, Operating
Reserve Requirements
Day ‐Ahead Market
(DA Market)
Real ‐Time Balancing Market
Reliability Unit Commitment
(RUC)
Requirements
Dispatch Instruction, cleared Operating Reserve
(MW)
DA Market Commitment
RUC Commitment
Day ‐Ahead Market
(DA Market)
Real ‐Time Balancing Market
Reliability Unit Commitment
(RUC)
Requirements
Dispatch Instruction, cleared Operating Reserve
(MW)
rCommitm
RUC Commitment(DA Market) (RTBM)(RUC) (MW)
(5 minute)
Commitment Commitment (DA Market) (RTBM)(RUC) (MW) (5 minute)
Commitm Commitment
DA Market & Net RTBM
DA Market Commitment, Cleared Energy and Operating Reserve (MW and Price) (hourly)
Dispatch Instruction, cleared Operating Reserve (MW and Price)
(5 minute)DA Market & Net RTBM
DA Market Commitment, Cleared Energy and Operating Reserve (MW and Price) (hourly)
EMS
Dispatch
Operating R(MW and Price)
(5 minute)
Settlements
Resource d L d
TCR Markets
Settlements
Resource d L d
TCR Markets
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and Load Meter Dataand Load Meter Data
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Additional Registration Activities
I ddi i h EIS i i• In addition to the current EIS registration activities, Market Participants will:
C fCertify generation capability to provide regulation, spin, and supplemental reserves
Test to validate ability to provide regulationTest to validate ability to provide regulation
Test ability to interact with all of the systems
• Additional training for the Transmission• Additional training for the Transmission Congestion Rights, Day Ahead Energy and Reserve Markets
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Future Markets Program Schedule - DRAFTFuture Markets Program Schedule - DRAFT
3Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13
Program Management
Analyze
Design
Build
Test
Deploy (Market Trials)
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Background• FERC is funding a SPP-Entergy Corporation Cost-
Benefit Analysis to evaluate the merits and costs of Entergy joining, or not joining, SPP (FERC SPP-Entergy CBA)Entergy CBA)
• The FERC SPP-Entergy CBA provides a foundation for the APSC directed cost benefit analysis tofor the APSC-directed cost-benefit analysis to evaluate the merits and costs of Entergy Arkansas, Inc. (EAI) joining, or not joining, SPP (APSC EAI CBA)
• The APSC EAI CBA leverages models, data, and
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assumptions in the FERC SPP-Entergy CBA77
Background, cont.
• “SPP Ready” costs - incremental investments S yrequired by Entergy (and EAI) to join SPP to meet SPP reliability requirements are zero
• SPP has not identified any reliability issues
Assuming completion of transmission expansion g p pprojects in the Entergy Construction Plan, including horizon projects
E t t i i i l th• Entergy transmission expansion plans are the same in all studies and scenarios
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Study 1 3 General NotesStudy 1 – 3 General NotesStudy 1-All Regional Costs: Entergy and Cleco are exposed to regional recovery of SPP upgrades completed after March, 2006 g y pg p ,coincident with first regional recovery in SPP. (Same approach used when Nebraska entities joined SPP in April 2009)
Study 2- Regional Costs after 1/1/13: Entergy and Cleco are onlyStudy 2 Regional Costs after 1/1/13: Entergy and Cleco are only exposed to regional recovery of SPP upgrades needed after the proposed “bright line” date of January 1, 2013. (Prospective)
Study 3-Regional Costs (Excluding BP and PP) After 1/1/13:Study 3-Regional Costs (Excluding BP and PP) After 1/1/13: Entergy and Cleco, as in Study 2, are only exposed to regional recovery of SPP upgrades needed after the proposed “bright line” date of January 1, 2013. Additionally, Entergy and Clecowere not exposed to Balanced Portfolio or Priority Project regional recovery. (Modified Prospective)
• For all Studies, SPP members are exposed to regional recovery of
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, p g yEntergy and Cleco projects beginning January 1, 2013
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General Notes, cont.• Differential results subtract Base Case Annual
T i i R R i t (ATRR)Transmission Revenue Requirement (ATRR) from Change Case ATRR; where:
Diff ti l Ch C B CDifferential = Change Case – Base Case
Change Case: Entergy and Cleco join SPP and share in regional recovery SPP traditionalshare in regional recovery. SPP traditional Transmission Owners also support Entergy and Cleco upgrades.
Base Case: Entergy and Cleco do not join SPP and therefore do not share in regional recovery. Entergy and Cleco fund their own upgrades
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Entergy and Cleco fund their own upgrades without SPP Transmission Owner support.
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M th dMethods• ATRR forecast was constructed for SPP Transmission
Owners Entergy and Cleco incorporating severalOwners, Entergy, and Cleco incorporating several upgrade types with several simplifying assumptions, e.g., maintain MW-MIs & BP balancing transfers, 3% d i ti t f ll d tdepreciation rate for all upgrades, etc.
• Host zone Net Plant Carrying Charge was applied to each upgrade to develop total ATRR for each upgradeeach upgrade to develop total ATRR for each upgrade
• Cost allocation was performed for each upgrade
• Focus was reallocation of regional, not zonal, ATRRs and the differential amounts ($M) between the base and change case over the 2013-2020 period
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and change case over the 2013 2020 period
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Key Inputs• Net Plant Carrying Charges
Entergy = 17.49% (self reported)
Cleco = 16.87% (self reported)( p )
• Load Ratio Shares
Entergy = 35 42% (calculated using ETR’s 2009 hourly loads)Entergy = 35.42% (calculated using ETR s 2009 hourly loads)
Cleco = 3.21% (calculated using CLE’s 2009 hourly loads)
E t d Cl d lf li d t SPP ITC• Entergy and Cleco upgrades self-supplied to SPP ITC
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Study 3 – Regional Costs (ExcludingStudy 3 – Regional Costs (Excluding BP and PP) After 1/1/13
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Concluding Remarks• Focus of these transmission cost allocation
studies have been exclusively costs notstudies have been exclusively costs, not benefits
It h ld b t d th t PP t• It should be noted that PP costs assume double circuit 345 kV, not 765 kV, projects in plainsp
• End effects and depreciation are driving results for 2017 +
• Results for 2020 will be extrapolated for 2021 and 2022 to complete 2013-2022 impacts
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and 2022 to complete 2013 2022 impacts
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APSC Order
APSC D k N 08 136 U O d N 10• APSC Docket No. 08-136-U, Order No. 10, dated May 29, 2009, ordered the EAI CBA:
“ C S“The Commission directs the Southwest Power Pool (SPP) to conduct, with the assistance of an independent third party, a comprehensive cost/benefit evaluation of full SPP membership by both Entergyevaluation of full SPP membership by both Entergy Arkansas, Inc. (EAI) (as a stand alone entity) and Entergy versus the existing ICT services arrangements as opposed to the status quo ante ”arrangements, as opposed to the status quo ante.
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Scope of APSC EAI CBA• EAI joining SPP RTO on a standalone basis
• Utilizes same underlying assumptions as FERC SPP-Entergy CBA
• Stand-alone EAI will be compared to EAI as part of SPP RTO
• Transmission cost allocations for EAI projects should EAI join SPP under the APSC EAI CBA
• Study timeframe is 2014 – 2022
EAI is scheduled to exit Entergy System Agreement in
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gy y gDecember 2013
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Upcoming APSC EAI CBA Milestones
S h d l d b l d i hi 30 d f hScheduled to be completed within 30 days of the final FERC SPP-Entergy CBA:
S CSeptember 7 – Charles River Associates update to EAI and stakeholders
September 10 – GE MAPS base and change casesSeptember 10 GE MAPS base and change cases completed
September 30 – DRAFT final report due
October 15 – Final report complete
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APSC EAI CBA Ongoing Process
S k h ld i• Stakeholder input process
Open
Transparent
• Additional sensitivity analysis
Scope
Timingg
Funding
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