Energy Imbalance Market Design Overview

Transcription

1 Energy Imbalance Market Design Overview Jim Price, Senior Advisor, Market Development & Analysis California ISO August 7, 2015, Puget Sound Energy

2 Topics for discussion Overview of EIM market offering & benefits Participant roles involved in EIM Base schedule, resource plan, & resource sufficiency Other inputs to market How bids are used Market results and settlement References: links to material beyond what is covered here 2

3 CAISO & EIM markets provide a responsive foundation for matching changes in supply & demand 60 Hz Day Ahead Market (CAISO) Hourly market for 24 hours of next day Establish energy and ancillary service schedules Manage congestion (transmission access) using Full Network Model (FNM) Determine residual unit commitment requirements Hourly & 15-minute Scheduling As start of real-time (RT) market, schedule energy and ancillary services for static hourly interchange and for 15-minute intervals Manage congestion using FNM As one of 4 RT pre-dispatch processes, establish unit commitment & advisory schedules for internal & dynamic resources Load Generation Real Time Market Manage energy flows on transmission grid with telemetry and 1-minute state estimator solutions Update FNM for RT conditions Dispatch balancing energy/ ancillary service 3

4 Energy Imbalance Market is an easily-scalable extension of real-time market to broader region Builds on existing market: automated dispatch facilitates renewables, resolves imbalance & avoids congestion Situational awareness enhances reliability FERC staff paper assessed EIM reliability benefits: -PotentialReliabilityBenefits- WesternEnergyImbalanceMarket.pdf No critical mass required. No exit fees Easily scalable, low-cost, low risk, voluntary option for new participants Preserves BAA autonomy, including compliance, balancing, and reserve obligations 4

5 Changing resource mix over the next 10 years presents new operational challenges Over 20,000 MW of wind and solar capacity is expected to be interconnected by 2020 Increased supply volatility Potential changes to load patterns as a result distributed generation and electric vehicles Changing, less predictable load patterns Approximately 18,000 MW of thermal generation will be repowered or retired by 2020 Uncertainty surrounding thermal resources o Phase out 12,000 MW of coastal plants with once-through cooling o Greenhouse gas reductions limit replacement generation o Water flow management affects hydro availability 5

6 What benefits can be realized through EIM? Inter-regional and intra-regional dispatch cost savings: BAAs start the hour with matched generation and forecasted load, but deviations occur within hours that is, imbalance energy Security constrained economic dispatch automatically resolves imbalance & avoids congestion, at least cost Optimization of unused transmission capacity within participants ownership or rights Greatest savings with single footprint, but can function even without transfers Flexibility reserves, renewable integration, reduced renewable curtailment: All BAs maintain reserves for contingency events Most BAs procure extra flexibility to balance variable supply and demand EIM combines geographical diversity of load and resources Increased reliability: Information that improves operational awareness and responsiveness to grid conditions across a large footprint (difficult to quantify) 6

7 EIM provides significant net benefits and will operate in eight western states Go Live Peak Demand (MW) ~ Annual benefits (in millions) ~ Start-up costs (in millions) ~ Annual ongoing costs (in millions) PacifiCorp NV Energy Puget Sound Energy November 2014 Arizona Public Service November 2015 Fall 2016 Fall ,500 8,148 4,912 7,000 $21-$129 $9-$18 (2017), $15-$29 (2022) $18-$30 $7-$18 $20 $11.2 $14.2 $13.5 $3 $2.6 $3.5 $4 7

8 Operating benefits over consistent with earlier benefit analysis, over $21 million for first 8 months Benefits include: Efficient, automated dispatch, both inter- and intra-regional, by 15- and 5-minute intervals Reduced renewable energy curtailment through resource & load diversity Reduced flexibility reserves (measured for PacifiCorp, to be added in future reports for CAISO) Benefits increase with more transfer volume between BAAs and higher market prices BAA Nov-Dec 2014 Jan-Mar 2015 April-June 2015 * ISO $1.24 M $1.45 M $2.46 M PACE $2.31 M $2.62 M $3.26 M PACW $2.42 M $1.19 M $4.46 M Total $5.97 M $5.26 M $10.18 M * The April-June 2015 analysis includes both 15 minute and 5-minute benefits. Prior reports only quantified 15-minute benefits. 8

9 Basics of EIM operation & settlement Base schedule: Forward energy schedule, including hourly load forecasts, generation schedules, and interchange schedules, as the baseline for EIM s financial settlements. Resource plan: How to balance supply and demand and ensure resource sufficiency: Load, generation, and interchange base schedules Energy bids from participating resources Ancillary service plans Other data: Outages, metering/ telemetry, transmission capacity A resource is dispatched at its location, and is paid the nodal price Load pays the weighted average price of all load nodes in the Load Aggregation Point (LAP) These examples are not meant to reflect actual resource or load locations 9

10 Several key roles are involved in enabling EIM participation ESC PRSC EIM Entity is a balancing authority that enables EIM to occur in its area. By enabling EIM and coordinating with its area s loads, resources and transmission service providers, all load and generation imbalances within its area will settle through the EIM. EIM Entity Scheduling Coordinator coordinates and facilitates EIM for one or more EIM Entities, and is responsible for resource plans and financial settlements on behalf of non-participating resources and loads. Base Schedule Coordinator submits base schedules and resource plans. EIM Transmission Service Provider controls transmission in the EIM Entity BAA, and voluntarily informs EIM Entity that it is making its transmission available for EIM. EIM Participating Resource is a resource within the EIM Entity represented by a Scheduling Coordinator that has voluntarily offers economic bids for availability in EIM s real-time market, subject to EIM Entity s eligibility requirements. EIM Participating Resource Scheduling Coordinator is certified to bid in ISO markets, submits bid, reports outages, and receives settlements and invoices. 10

11 EIM Entities and Participating Resources determine key aspects of participation EIM Entity determines: Eligibility of resource types (generators, participating loads & demand response, non-generator resources, etc.) Types of eligible dynamic transfers (dynamic schedules, pseudo-ties) Eligibility of 15-minute economic bidding on its interties Requirements of transmission service within its BAA Definition of Load Aggregation Points Settlement of EIM charges or credits to entities within its BAA EIM Participating Resource determines: Registration to participate in EIM Hour-to-hour quantity and price of economic bids 11

12 The EIM implementation process depends on information from EIM Entity and EIM Participating Resources, including: Agreements Metering and telemetry Modeling (to 3 MW generator size for PacifiCorp) Resource parameters 12

13 Prior to each dispatch, EIM receives a variety of inputs to automatically assess the entire footprint Economic benefits Reliability benefits 13

14 EIM participants submit base schedules and resource plans to initiate the market Loads Nonparticipating resources Participating resources Base Schedules Base Schedules Base Schedule EIM Entity - SIBR - EIM Base Schedules Rules & workflow Base Schedules Visibility & override supply/load MW mismatch, supply and load base schedules, network flow MW overloads Financially Binding Base Schedules Powerflow (balance & feasibility) C Real-Time Market Application Financially Binding Base Schedules Balance & Feasibility Results - CMRI - EIM Balance & Feasibility Reports Financially Binding Base Schedules EIM Entity Scheduling Coordinator has full visibility of all base schedules. 14

15 After advisory feedback period, interactive resource sufficiency evaluation prevents leaning among BAAs Resource sufficiency tests: Balanced load and generation? Free of congestion? Sufficient ramping capability? T-75: Base schedules and energy bids due (Resources) T-55: Updated base schedules are submitted if necessary (Resources) T-40: Updated base schedules are submitted if necessary (Entity SC) T-20: E-tagging deadline (Entity SC) T-37.5: Start of Market 1 optimization T-45: Results of sufficiency test published T-60: Results of sufficiency test published (Balanced? Feasible transmission? Sufficient flexible ramping?) T EIM Market Participants 15-minute dispatch intervals (4.5 hour look-ahead) X:00 X:15 X:30 X:45 Y:00 5-minute dispatch intervals (65-minute look-ahead) T-22.5: 15-minute scheduled awards published Market Operator (T = start of the hour) 15

16 15-minute market (FMM) allows ISO intertie bidding, using transmission profile on dynamic schedule e-tag to manage EIM transfers Both an overall intertie scheduling limit and an EIM transfer limit apply in FMM Transmission Profile on e-tag ISO EIM Transfer Limit EIM Entity BAA Only the EIM transfer capacity offered through EIM Entity is available in RTD (also constrained by variable transfer limit) Biddable nodes Non-biddable nodes (non-participating resources) 16

17 Real-time outputs 17

18 Market systems for publishing results depend on purpose of the outputs 18

19 Automated Dispatch System sends real-time binding instructions Energy dispatch to meet imbalance requirements 15-minute reserves, e.g., for flexible ramping Resource startup and shut down instructions Dispatch of static system resources Contingency and exceptional dispatches 19

20 Participant-specific market results are available in Customer Market Results Interface, through Market Participant Portal ( CMRI Market results MW Market results - $ Base schedule information 20

21 Oasis.caiso.com provides extensive public information Prices Locational marginal prices Constraint shadow prices Fuel and reference prices Transmission Available capacity Usage Outages System demand Demand forecasts Wind & solar forecasts Ancillary services Reserve requirements Market awards Actual reserves Energy Load and resource schedules Exceptional dispatch Market power mitigation Resource adequacy Virtual bidding Losses Congestion revenue rights Auction clearing prices Inventory of awards Public Bids Market bids with certain fields masked, with 90-day delay 21

22 The ISO settles with scheduling coordinators, who allocate payments and charges to the appropriate customers. Market Operator settles deviations of EIM Participating Resources from base schedules at LMP of resource locations. For resources that do not participate in EIM, Market Operator settles with EIM Entity Scheduling Coordinator, who is responsible for settlement of deviations from their base schedules. 22

23 Real-time energy charge codes reflect cost causation. Primary settlement: instructed and uninstructed imbalance energy. Illustrative set of common charge codes (See for further detail) Instructed Imbalance Energy (IIE) Uninstructed Imbalance Energy (UIE) Other settlements Bid Cost Recovery (ensures resources recover daily RT costs, recovered within BAA with EIM Transfer considered) Unaccounted for Energy (UFE) Congestion Offset (neutrality accounts by BAA) Marginal Losses Offset (neutrality accounts by BAA) Imbalance Energy Offset (can shift costs or payments between BAAs based on EIM Transfers) Greenhouse Gas Emission Cost Revenue EIM Administrative Charge ($0.19/MWh imbalance energy) 23

24 When resources deviate from dispatches (or base schedules), other resources must be dispatched to maintain balance. Meter = 12 MW Instruction 10 MW Uninstructed Imbalance Energy = 2 MW, as payment for delivered energy Instruction 10 MW Meter = 7 MW Uninstructed Imbalance Energy = -3 MW, charged to resource for undelivered energy Instructed imbalance energy is the energy in dispatch instructions, then uninstructed imbalance energy is the difference between the dispatch and meter. 24

25 Settlement statement timeline provides prompt clearing, with later changes limited to unresolved disputes or FERC decisions Initial settlement statement T+3B (uses estimated settlement meter data) Recalculation settlement statement T+12B, T+55B Disputes due T+26B, T+77B Recalculation settlement statement T+9M through T+36M (optional) Disputes limited to only incremental charges 25

26 Recap: EIM extends ISO s real-time market experience and systems to EIM participants Optimized 15- and 5-minute interval dispatch accounts for operating characteristics and constraints of participating resources as well as the underlying transmission Multi-interval look-ahead horizons anticipate changes in system conditions and ensure flexibility of dispatch, to efficiently manage system balance and congestion Short-term unit commitment allows efficient economic dispatch, recognizing state-of-art renewable energy forecasts, hydro limits, complexity of resources like combined-cycle, and other factors The result is efficient use of transmission offered by EIM participants & cost reduction to consumers 26

27 What changes for reliability entities? If you are: Balancing Authority Current NERC and WECC responsibilities will not change May commit resources as they do today Manage interchange tagging Will be EIM Entities Will submit balanced schedules to the Market Operator Will communicate with Market Operator about outages and operating limits Transmission Owner, Transmission Operator, Transmission Service Provider (TSP) TSP determines available transmission capability (ATC) and prior commitments, to inform Market Operator of capacity available for EIM Transfers No other change in role or responsibilities 27

28 If you are: What changes for market participants? Utility affiliated with EIM Entity Other Utility in EIM Entity BAA Resource (e.g., merchant generator) in EIM Entity BAA Submits load and resource information to Market Operator as well as EIM Entity BA Submits load and resource information to Market Operator as well as EIM Entity BA If electing to participate in EIM as an EIM Participating Resource Communicate availability through SC Provide outage information to Market Operator as well as EIM Entity BA Respond to dispatch instructions Scheduling Coordinator Submits bids and schedules for EIM participants Receives settlement statements and invoices from ISO 28

29 Resources available for EIM CBT - Introduction to the Energy Imbalance Market This Computer Based Training provides a high level overview of the Energy Imbalance Market 20to%20the%20Energy%20Imbalance%20Market/player.html CBT - How the Energy Imbalance Market Works This Computer Based Training describes the roles and responsibilities of the key players in EIM and the business processes that will take place. EIM Stakeholder processes and tariff filings EIM Business Process Manual Imbalance Market 29

30 Additional Information

31 California ISO is one of 9 ISO/RTOs in North America, providing open, non-discriminatory transmission access Responsibilities: Reliability, grid planning, outage coordination Market development, operations, monitoring 23% renewables (biogas, biomass, geothermal, small hydro, solar, wind) 10% nuclear 7% large hydro (2014 drought, more commonly ~14%) <1% coal <1% oil 59% natural gas CAISO manages approximately 80% of California s electricity load 50,270 MW record peak demand (7/24/2006) $8.5 billion annual market (2012) 60,703 MW in-state power plant capacity 16,470 MW import capacity 26,024 circuit-miles of transmission lines 30 million people served 246 million annual megawatt-hours of electricity delivered (2012) 38,000 generation & transmission outages per year 26,500 market transactions per day 31

32 EIM Transitional Committee is finalizing a governance proposal for EIM matters Issue Paper Straw Proposal Revised Proposal TC Approval ISO Board Approval Governance Implementation Jan 2015 Spring Summer Fall 2016 Transitional Committee is an advisory committee to ISO Board consisting of 13 members The committee is following an iterative stakeholder process for the development of the governance proposal Transitional Committee s proposal to be finalized in August and presented to the ISO board in September. It outlines: o relationship between ISO Board and EIM body o nature and degree of the influence over EIM rules o makeup and criteria for board members o process for selecting new members o formation of an advisory body of state regulators 32

33 Changing resource mix leads to changes in pattern of net load for dispatch, with new needs for market products Load & Net Load (MW) 34,000 32,000 30,000 28,000 26,000 24,000 22,000 20,000 18,000 6,700 MW in 3-hours Load, Wind & Solar Profiles -- Base Scenario January ,000 MW in 3-hours 12,700 MW in 3-hours 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 Wind & Solar (MW) 16,000 1,000 14,000 0 Net_Load Load Wind Total Solar Net Load = Load - Wind - Solar 33

34 New events (like negative energy prices indicating risk of over-generation) introduce new opportunities for economy energy, load management, etc. 22,000 ISO's Net Load vs. Average 5-Minute Energy Prices April 12, , ISO's Net Load (MW) 20,000 19,000 18,000 17,000 16,000 15, Minute Energy Prices ($) 14, Net Load MCP_RTD 5-Min_Prices<=Zero 5-Min_Prices>$100 Example, April 12, 2014: Coincident MW of wind & solar was 35% of total 23,450 system load, dropping net load to 15,000 MW. With limited decremental bids, energy prices were zero or negative (blue dots) for 43% of 5-minute RTD intervals

35 Market Operator (ISO) determines load and resource forecasts, and runs and settles the market. Initial optimization starts to manage congestion and refine inputs Market optimization ensures physical resource feasibility by refining network constraints, iterating between network analysis and optimization Optimization uses Mixed Integer Programming 35

36 ISO markets build on full network model & energy management system (EMS) state estimator Detailed network model is foundation for grid (EMS) & market operations: Both model Western region, mostly the same Real-time market starts from current state estimator solution o 167,000 telemetry data points, including 17,000 for PacifiCorp, adding 11,000 for NV Energy o State estimator solves every minute, including contingency analysis 36

37 Day-ahead advisory process for EIM runs with ISO s market, for feedback on feasible scheduling The process begins 7 days before the operating day. EIM Entity SC may submit demand forecasts to the ISO. The ISO provides hourly demand forecasts to the market. By close of ISO s day-ahead market, EIM Entity BSC submits base schedules for participating and non-participating resources to the Market Operator. ISO s day-ahead market models EIM Entity BAA and informs EIM Entity of issues to address.. 10:00 1:00 37

38 Building on FERC Order 764 with financially binding 15- and 5-minute functions promotes market efficiency CAISO Day Ahead Schedule EIM Base Schedule (basis of financial settlement) 15-Minute Unit Commitment & Energy Schedule, and Incremental AS Awards 15-Minute Unit Commitment & Energy Schedule 5-minute Real-Time Dispatch Settlements apply to incremental changes from previous market process 38

39 EIM Entity s base schedule should be balanced prior to start of real-time market Demand (load, exports, & losses) = Resource plans: base schedules Self-scheduled resources Base generation schedules Intertie schedules Resource plans also include: Ancillary services reservations protected from dispatch Operational characteristics (e.g., ramp rate) Economic Bids Base schedule must be balanced or they will be adjusted prior to start of EIM. 39

40 Under- and over-scheduling penalties provide incentives for balanced base schedules No exposure to penalty if EIM Entity using Market Operator forecast If Market Operator demand forecast differs from EIM Entity SC base schedule supply by >1%, then deemed to be using own forecast and subject to penalties If EIM Entity is using own load forecast for base schedule If load imbalance exceeds 5% (but at least 2 MW) of actual demand, then Price for excess demand = 125% of the LAP s Locational Marginal Price (LMP) Price for excess supply = 75% of applicable LMP If load imbalance exceeds 10% of LAP, then Price for excess demand = 200% of the LAP LMP Price for excess supply = 50% of applicable LMP Revenue collected over day allocated to EIM Entities that have not incurred a scheduling penalty in any hour of the day 40

41 Energy bids provide the ability to cover fluctuations in load. $/MWh $50 $40 $35 Clearing price Economic Bid $30 $20 $10 Bid range MW 41

42 Economic bids in resource plan ensure real-time balance, feasibility and flexibility of deviation from base schedules Hourly base schedules (Forward energy schedule; including hourly generation and interchange schedules, as a baseline for financial settlements). Base schedules must be within economic bid ranges (e.g., the base schedule for a participating resource with a bid from 10 to 100 MW could not exceed 100 MW.) Actual operation Bid range Resource Plan: Available resources to balance supply and demand and evaluate resource sufficiency. Comprised of: Load, generation and interchange base schedules Energy bids from participating resources Ancillary service plans 42

43 Along with forecasts & market inputs, current operational data are also needed: metering, outages, transmission Telemetry data is communicated from the EIM Entity to the Market Operator via ICCP. With implementation of the EIM, ISO allows scheduling coordinators and other entities submitting meter data for EIM resources to submit meter data in the following granularity levels: a) Generation for participating generators at 5-minute intervals; non-participating generators at 5, 15 or 60- minute intervals. b) Interties at 5-minute intervals. c) Load at 5, 15 or 60-minute intervals. Metering standards are determined by local regulatory authority. 43

44 Given the inputs, market determines optimal dispatch and resulting 15- & 5-minute locational marginal prices (LMPs) Energy: Changes in system demand and supply cause incremental dispatches. Uniform system energy price differs by location due to congestion and losses. Congestion: Due to limited transmission capacity or outages, lowest-priced electricity can t flow freely Loss: Energy is lost as it flows through the grid. LMPs include incremental change when serving additional load. Greenhouse Gas: California regulations apply to resources that serve load in CAISO BAA. Optimization dispatches for least cost, recognizing compliance costs. GHG component compensates resources and avoids charges to non-ca load. Separate bid component shows availability for dispatch. Locational Marginal Price ($/MWh) Demand Supply bids Market Clearing 44

45 Real-Time Economic Dispatch (RTD) meets 45 energy balance in 5-minute intervals 45

46 Ramping capacity ensures sufficient flexibility in RTD to manage the probability of varying grid conditions, and enable sharing of diversity Flexible ramping: Secures ramping capability in 15- minute market & RT dispatch Forward-looking procurement, considering future uncertainty Compensates resources whose dispatch is held back in financially binding interval to meet future ramping needs Allocates costs to movement that requires others to be Energy dispatched Energy Product enhancements (Fall 2016): Add bidding & flexible downward ramping Replace flexible ramping constraint compensation & cost allocation 46

47 Real-time self-schedules (e.g., forecasted VER output, e-tag curtailments, reloads) may be updated before 15-minute intervals T-37.5: FMM Optimization Starts T-22.5: FMM Energy Schedule Awards T-5: FMM Energy Schedule e-tag Deadline 20 Minutes T FMM interval 37.5 Minutes T-40: Schedule change can be reflected in FMM dispatch, as instructed imbalance energy Intertie changes up to 20 minutes before 15-minute intervals are allowed but may be limited by e-tag s transmission reservations. Any difference between the FMM intertie schedule and change in selfschedule will be settled at the RTD price, not FMM price, until FMM can recognize schedule change.. 47

48 Price stability after November 14 shows importance of current knowledge of outages, operator response, and sufficient available resources 15-minute Market Aggregate Price, PacifiCorp West 15-minute Market Aggregate Price, PacifiCorp East Waiver effective Waiver effective 48

49 Various factors caused PacifiCorp s initial MW undersupply Outages, derates/rerates management Timely informing the market about out-of-market actions impacting energy balance Wind forecast accuracy and managing wind deviations Data and software issues Within the hour interchange schedule variations Load forecast variation and load biasing coordination Network and resource model discrepancies 5 minute rate of change constraint on some transmission interfaces Waiver of pricing rules let prices be set by economic bids rather than constraint violations. CAISO is proposing ongoing transition mechanism and readiness criteria for new EIM Entities. 49

50 Outage rates for participating gas and coal capacity in PacifiCorp West averaged about 10 percent 50

51 Outage rates for participating gas and coal capacity in PacifiCorp East averaged about 15 percent but much higher in some hours 51

52 Transmission service uses simple principles EIM Entities make transmission capacity available through dynamic e-tag and transmission registry: EIM Participating Resources can offer contracted capacity, and EIM Entities offer unsold capacity confirmed through standard dynamic e-tag Network service within EIM Entities allows redispatch up to network capacity EIM coordinates transmission usage with EIM participants Transmission Service Providers (e.g., Bonneville Power Administration (BPA) in PacifiCorp s case) EIM transfers respect both scheduling rights and actual flow constraints. ISO constantly updates EIM Entities NSI to reflect EIM transfers Reciprocity: To consider bids equally on economic merit, initial design proposed no incremental charge for transmission for EIM transfers between EIM Entities EIM maintains existing transmission rate structures within EIM Entities 52

53 For PacifiCorp, separate static and dynamic schedules manage EIM transfers within variable transfer limits (VTL) Illustrative example: TR rights available for EIM = 200 MW VTL = ±50 MW Static e-tag TR = 150 En = 145 = FMM Before bid closure, PacifiCorp creates dynamic and static e-tags across COI with transmission profiles for maximum allowed EIM flows on COI. EIM produces 15-minute awards at T-22.5 minutes for each FMM interval, updates the static e-tag (four times per hour), then issues 5-minute dispatches within these intervals within BPA s VTL limits. Dynamic e-tag TR = 50 En = 50 (updated after the hour) After the hour, the dynamic e-tag s energy profile is updated to the hourly average of 5-minute dispatches. Results Published T-22.5 En=145 En=140 En=140 En=150 FMM run starts at T using 15-minute Limit = 150 FMM Intervals 53

54 EIM year one enhancements are pending at FERC Scalability of EIM design: Optimal management of multiple EIM transfer limits Flexible ramping constraint BAA combinations Compliance with 6/19/2014 FERC Order: Greenhouse Gas flag and cost based bid adder Implementation details: EIM administrative charge redesign Administrative pricing rules (price to use in market disruption) Settlement rules for non-participating resources Phase 2 (just started) will consider transmission usage charges plus other enhancements 54