APS Stakeholder Meeting. September 9 th 2016

Transcription

1 APS Stakeholder Meeting September 9 th 2016

2 APS: EIM Implementation & Customer Impact Review 9/9/2016

3 Emerging Market Opportunity CAISO: Energy Imbalance Market Existing Markets 3

4 Changing Electrical Grid Nuclear Coal Natural Gas Renewable Energy Energy Efficiency 4

5 Why APS Decided to Join CAISO EIM EIM provides an opportunity to take advantage of wholesale market evolution Increased flexibility to handle intrahour fluctuations in _generation and load Supports integration of renewable generation Lowers net fuel costs Customer benefit Strengthen reliability through increased grid visibility and hour ahead tests 5

6 APS Implementation New Software Systems tested and installed Completed Market Simulation Filed FERC Readiness Currently in final stage: Parallel Operations On Schedule for 10/1 EIM Entry Milestones Implementation Agreement Joint Project Plan with CAISO Tariff Development OATT Filed with FERC System Testing Market Simulation 30 day FERC Readiness complete Go Live 05/28/2015 7/15/ / / / / /01/ /01/ /1/2016 6

7 Review of Customer Impacts 7

8 Base Schedules Definition Base Schedules: must be submitted for all generating resources in an EIM Entity BAA, including EIM non-participating resources and must include disaggregation of forward export schedules to other BAAs. Base import schedules to an EIM Entity BAA from BAAs other than CAISO must be submitted at the relevant intertie scheduling points. A Base schedule is a forward energy schedule with hourly granularity that is the baseline to measure deviations for settlement through the EIM. Base Schedules include the hourly forecasts of load, hourly generation schedules, and hourly interchange schedules. APS Implementation: APS is utilizing E-Tags to develop base schedules for transmission availability and non-participating generation resources All EIM Settlements are based on E-Tag information submitted before T-57 Entities may be subject to additional imbalance charges if E-tags are submitted or adjusted after T-57 8

9 Load Customers Current Practice Future Practice 10/1/2016 Metering 60-minute metering No Change Scheduling E-Tag E-Tag, Submitted before T- 57 Settlements Bill Frequency ICE weighted average Palo Verde, Four Corners, and Mead index day-ahead prices. Monthly (before the 25th of the following month). Load Aggregation Point (LAP) Hourly prices. No Change *Preliminary daily schedule imbalance reports for added transparency. 9

10 Wheeling Customers (Without Load or Generation in APS s BAA) Current Practice Future Practice 10/1/2016 Scheduling E-Tag T-57 Settlements Losses based on final E-Tag value Losses based on T- 57 Bill Frequency No imbalance Charges Monthly (before the 25th of the following month). Imbalance charges will be assessed on E-Tag after T- 57 changes No Change *Preliminary daily schedule imbalance reports for added transparency. 10

11 Generation Customers Current Practice Future Practice 10/1/2016 Metering 15-Minute metering capability 5-minute metering capability Scheduling Final E-Tag T -57 through Final E-Tag Settlements Bill Frequency ICE weighted average Palo Verde, Four Corners, and Mead index dayahead prices. Monthly (before the 25th of the following month). CAISO will settle directly with Participating Resources at Locational Marginal Prices (LMP) Non-Participating Resources will be directly assigned CAISO imbalances based on deviations from T-57 No Change *Preliminary daily schedule imbalance reports for added transparency. 11

12 Business Practice Review

13 Business Practice Overview APS will have a total of Four Business Practices for EIM: Application and Certification Initial application Verification Certification Data Submissions Registration and updates for both participating and non-participating resources Model Data Forecast Data Outage reporting and management Billing and Disputes Settlements and billing Over-scheduling load Under-scheduling load Dispute resolution EIM Suspension or Termination Termination of EIM by APS Notice regarding corrective actions 13

14 EIM & Settlements Kent Walter September 9,2016

15 Training Agenda Concepts Settlement Changes EIM Allocation Questions 15

16 Concepts EIM Concepts that create need for suballocation

17 Redefines Imbalance EIM redefines imbalance to reflect actual flows of the system MW added to system are not the MW pulled from the system. System constraints and transmission losses may change the true cost of MW between points EIM Imbalance applies to resources, loads, imports, and exports Current Business Reality EIM 17

18 Locational Marginal Pricing ( LMP ) Locational marginal price ( LMP ): Energy Congestion Losses Cost to provide the next MW of power at a specific point on the network Generation cost Impact of transmission outages and constraints Cost of line losses EIM is used to determine the lowest LMP possible at each delivery point to serve the entire footprint s energy needs 18

19 LMP (cont.) Gen $20/MWh Load Imbalance 200 Pricing Node Path Limit 250 AZPS BAA AZPS BAA SRP BAA WALC BAA Gen $30/MWh LMPs without congestion between typically have little price difference 19

20 LMP (cont.) Gen $20/MWh Load Imbalance 200 Pricing Node LMP $20/MWh Path Limit 250 AZPS BAA LMP $20/MWh AZPS BAA LMP $20/MWh $20 Energy $ 0Congestion $ 0 Losses LMP $20/MWh WALC BAA Gen $30/MWh LMP $20/MWh SRP BAA LMPs without congestion between typically have little price difference 20

21 LMP (cont.) LMPs separated by congestion may have more substantial deviations between in price Gen $20/MWh Load Imbalance 200 Pricing Node Constrained Path AZPS BAA AZPS BAA Limit 100 SRP BAA WALC BAA Gen $30/MWh 21

22 LMP (cont.) LMPs separated by congestion may have more substantial deviations between in price Gen $20/MWh Load Imbalance 200 Pricing Node LMP $20/MWh Constrained Path AZPS BAA LMP $30/MWh AZPS BAA LMP $20/MWh $30 Energy $-10 Congestion $ 0 Losses Limit 100 LMP $20/MWh LMP $30/MWh WALC BAA Gen $30/MWh SRP BAA LMP $30/MWh $30 Energy $0 Congestion $ 0 Losses 22

23 Settlement timing considerations Base Schedule FMM 1 FMM 2 FMM 3 FMM 4 ATF T-57 minute tag cut off T-37.5 minute* T-22.5 minute* T-7.5 minutes* T+7.5 minutes* T+7 days *Time provided is market timing tag submittal included in market run based on processing time 23

24 Timing - Intervals Imbalance Shorter intervals reduce imbalance from optimization to load Imbalance Imbalance 24

25 Settlements Changes How EIM Concepts have changed settlements for transmission services

26 Settlements Not Impacted by EIM Transmission service Schedule 2 - Reactive Supply & Voltage Control Schedule 3 Regulation and Frequency Response Schedule 5 Operating Reserves - Spinning Schedule 6 Operating Reserves - Supplemental 26

27 EIM Market Timing Forecast submittal Forecast submittals for service is required beginning at T-7 days Must update at forecast at least once by T-1 day Forecasts serve to support market functions but are not financially binding until base schedule submission Base schedule submittal Final base schedule submission at T-77 minutes modifications are accepted up to T-57 minutes Base schedules serve multiple market functions Adjustments after base schedule submits Transmission customers have full access to purchased transmission rights past base schedule submission; however, settles as imbalance at the respective LMPs 27

28 EIM - Pricing Proxy Existing Pricing Proxy Weighted average ICE price for Palo Verde, Four Corners, and Mead for all imbalance and losses Proposed Pricing Proxy Resources and interchange changes after base schedule submission at LMP Load and Losses at LAP 28

29 EIM Losses Settlements Existing losses settlements Proposed losses settlements Scheduled energy 2.5% loss factor Pricing proxy Scheduled energy at base schedules 2.5% loss factor LAP Price Loss component settles as part of imbalance after base schedules 29

30 EIM Energy and Generator Imbalance Reference Schedule 4 Schedule 10 Service Interval Price Penalty Tiers Load Imbalance Hourly Load Aggregation Point ( LAP ) Not at this time Generator Imbalance 5-minute LMP Not at this time 30

31 EIM Allocations New settlements resulting from EIM which are allocated through the APS OATT

32 EIM Allocations Direct Allocations Measured Demand Metered Demand Generator & Load Imbalance 32

33 Direct Allocation Imbalance Energy Fifteen Minute Market ( FMM ) Instructed Imbalance Energy ( IIE ) Real-Time Imbalance Energy ( RTD ) Purpose RTD IIE RTD Uninstructed Imbalance Energy Directly allocate costs for wholesale activity post base schedule 33

34 Direct Allocation Schedule based imbalance Schedules or tags define the imports or exports Compliments Energy and Generator Imbalance 34

35 EIM Direct Assignment Settlement Timeline Operating Day T T+7CD Schedules Finalized As applicable Daily Checkout Detail Revisions By 25 th of following month Issue Customer Invoice T+3B CAISO Initial Statement T+10CD Preliminary Daily Checkout Detail Around 15 th of following month Monthly Summary Checkout Data As applicable Future Revisions *Green text identifies activity at election of customer 35

36 Detailed Daily Checkout Daily Checkout Statement Customer may elect not to receive this detail Checkout Detail Preliminary sent T+10 Calendar Days ( CD ) File name contains settlement date: YYYYMMDD Monthly Summary Checkout Data Daily summaries of checkout detail Total Daily Imbalance and Total Daily Settlement 36

37 Position Name Location for Schedule Imbalance Sets price and traceability to tag data APS providing customer resource on OASIS Type of Service Customer PSE Code BA Tag Scheduling Point Transfer Type Sub Type of Service Resource or Load P_APS_SRP_WESTWING500_TID_NF_RES 37

38 Allocations by Measured Demand What is this? Measured Demand ( MD ) Exports (that don t sink in AZPS) plus load Method of creating an allocation for costs which cannot be directly associated with a specific market participant Ratio-based allocation based on customers percentage of measured demand Use Cases: Load Serving Remote Gen Import/Export Export 38

39 Measured Demand based Allocations * ISO Market Charge Code Number ISO Market Charge Code Name GMC-EIM 4564 Transaction Charge Real Time Bid Cost Recovery Allocation EIM Real Time Congestion Offset EIM Group Grid Management Charge Bid Cost Recovery Congestion Time Interval 5 Mins 5 Mins 5 Mins * ISO Market Charge Code Number ISO Market Charge Code Name Group Flexible Ramp Up 7056 Ancillary Services Cost Allocation Daily Neutrality 8989 Adjustment PTB (Pass Through Bills) Time Interval Daily Daily Real Time Marginal Losses Offset EIM Real Time Energy Real Time 6478 Imbalance Energy Real Time Energy Offset - System Real Time Imbalance Energy Real Time Energy Offset EIM 5 Mins 5 Mins 5 Mins * ISO Market Charge Code Number ISO Market Charge Code Name SMCR - Settlements, 4575 Metering, and Client Relations Monthly 8999 Neutrality Adjustment Group Grid Management Charge PTB (Pass Through Bills) Time Interval Monthly Monthly 39

40 Measured Demand Checkout Normal settlements timeline Roll-ups based on charge code (hourly, daily, monthly) Hour Customer MD System MD Allocations Settlement $5600 $ $3004 $ $3004 $ $5004 -$

41 Metered Demand Over-scheduling penalty and allocations Under scheduling penalty and allocations Purpose Determine parties that contributed to whole footprint over or under scheduling and allocate penalty based on their percentage contribution to the event. 41

42 Metered Demand Only applicable to customers with Load in the BAA Checkout for component of Load imbalance similar to checkout seen today See APS Business Practices 42

43 Generator and Load Imbalance Schedule 4 Imbalance based on base schedules Removal of penalty tiers Use of APS LAP price as proxy Schedule 10 Is directly allocated from CISO statement to customers statement Imbalance in 5 minute and 15 minute markets at LMP price 43

44 Questions