1. Development of CAISO / PacifiCorp Energy Imbalance Market Briefing on CAISO Straw Proposal & Benefit Study
Presentation to WECC Market Interface Committee, July 18, 2013
Jim Price, Senior Advisor, Market Development & Analysis, CAISO
Additional info:

2. Presentation overview: PacifiCorp implementation and EIM stakeholder process are in progress (following study of benefits)
2013
2014
Implementation agreement
FERC
review
Implementation work
System testing market simulation
Board authorization 3/20/2013
Filing 4/30/2013
FERC acceptance 6/28/2013
Process Merger
Go live 10/1/2014
tariff language
EIM stakeholder process
FERC
review
Expand on principles in the MOU
Establish the project description and schedule
Description based on EIM straw proposal
Schedule identifies project tasks
Board authorization 11/8/2013
Filing
FERC acceptance
Stakeholder meetings:
4/11/2013 – Folsom
6/6/2013 – Folsom
7/9/2013 – Phoenix
8/20/2013 – Portland
9/30/2013 – Folsom

3. March 2012, CAISO proposed a scalable approach for implementing Energy Imbalance Market (EIM)
No critical mass required – each participant can enter EIM when ready
Preserves participants’ autonomy and current practices
Balancing authorities balance and provide their own ancillary services
Balancing authorities can trade bilaterally
Participants retain all physical scheduling rights
Flexible modes of participation are available
BAA 1
BAA 2
BAA 3
Confidential - Attorney Work Product - Prepared in Anticipation of Litigation

4. CAISO proposed a scalable approach for implementing Energy Imbalance Market (EIM)
network modeling
transmission monitoring
BAAs
bidding/self-scheduling
intra-hour dispatch
settlements

5. Benefits of Energy Imbalance Market
Leverages existing CAISO market
Enhances reliability through improved situational awareness in CAISO and EIM footprint
Captures the benefits of geographical diversity of load and resources
Potentially reduces reserve requirements
Provides easy entry/exit for EIM participation

6. Energy Imbalance Market definitions
EIM Entity is a balancing authority that enters into the pro forma EIM Entity Agreement to enable the EIM to occur in its balancing authority area (BAA). By enabling the EIM, real-time load and generation imbalances within its BAA will be settled through the EIM.
EIM Participating Resource is a resource located within the EIM Entity BAA that is eligible and elects to participate in the EIM.
In the 5-minute market, eligible resources may include Generating Units, Physical Scheduling Plants, Participating Loads, Proxy Demand Resources, Non-Generator Resources and Dynamic Schedules.
In the 15-minute market, imports and exports that can be scheduled on a 15-minute basis are also eligible to participate.

7. FERC Order 764 introduces financially binding 15-minute market to real-time market design
CAISO
EIM
Day Ahead Schedule
Base Schedule
15-Minute Schedule
15-Minute Schedule
Real-Time Dispatch
Real-Time Dispatch

8. Real-time market processes
Hour Ahead Process
CAISO accept block intertie transactions
15-Minute Market: Real-Time Unit Commitment (RTUC)
CAISO unit commitment, incremental AS, energy schedules
EIM energy schedule changes from base schedule
5-Minute: Real-Time Dispatch (RTD)
Energy dispatch within CAISO and EIM footprint

9. Market input data As needed Prior to operating hour (T-75 minutes)
Resource operational characteristics
Network model topology
Static contingencies observed
Prior to operating hour (T-75 minutes)
Economic bids and hourly base schedules
Ongoing
Transmission and generation outages
15-minute base schedules
Load and VER forecasts
Dynamic contingency list
Actual ETC/ATC scheduling limits and ETC uses

10. Hourly process for real-time market
T-75: Real-Time Bid Submission Deadline
T-45: Results from Hourly Process to Accept Block Schedules Published
T-20: Intertie Hourly Transmission Profile and
Energy Schedule for Market 1 E-Tag Deadline T
T = Start of the Hour
T-37.5: Start of Market 1 Optimization
No hourly financially binding schedules in real-time

11. 15-Minute market timeline under FERC Order 764
Financially Binding
Market 2
T-5: Market 2 Energy Schedule E-Tag Deadline
T-22.5: Self Schedule Changes for Market 2
T-7.5: Market 2 Energy Schedule Awards T
T-22.5: Market 2 Optimization Starts
37.5 Minutes
20 Minutes
T = Start of the Hour
Honor intra-hour 20 minute e-Tag submission to avoid seams issues

12. RTD Market Timeline under FERC Order 764
Financially Binding
Market 1
Market 2
T+15
RTD 4
RTD 2
RTD 6
T+7.5: RTD 4 Optimization Starts
T+12.5: RTD 4 Dispatch, RTD 5 Optimization Begins
RTD 3
RTD 5
T = Start of the Hour
7.5 Min
No changes to RTD 5-minute dispatch
RTD provides operational instruction to all generation and demand response resources

13. Establishment of Load Aggregation Points (LAP)
EIM Entity defines the LAPs within its BAA
For example, internal to the CAISO LAPs are defined by utility service territories
The number of LAPs must be weighed against the availability of multiple granular load forecasts
CAISO will determine Load Distribution Factors (LDFs) using its state estimator
CAISO uses LDFs to distribute LAP forecast to individual nodes within the network model
CAISO publishes LDFs used in the day-ahead market process three days after the trade date

14. Load forecasting Load forecast by LAP should:
Be the net of “behind the meter” generation
Include losses
Two options for load forecast for establishing base schedule:
Use ISO forecast
Use EIM Participant forecast, but subject to under-scheduling charges when errors exceed 4% threshold

15. Base schedule should be balanced prior to start of real-time market
Load forecast from prior slide
Resource plans: base schedules
Self-scheduled resources
Intertie schedules
Base generation 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.

16. Market optimization uses the economic bids submitted at T-75 minutes
CAISO will provide advisory feedback on schedules up to the binding 15-minute market, so base schedules can be developed without congestion
15-minute process builds on FERC Order No. 764
Multi-interval Security Constrained Unit Commitment, with 15-minute interval granularity
Imbalance energy = difference between base schedule and 15-minute schedule
5-minute dispatch process
Multi-interval Security Constrained Economic Dispatch, with 5-minute interval granularity
Imbalance energy = difference between 15-minute schedule and 5-minute dispatch

17. Congestion management
CAISO will manage congestion in EIM by automatically activating constraints, before flows approach capacity
This allows the EIM dispatch to try and resolve the congestion
Alerts the EIM Entity that they may be required to initiate UFMP
Once activated, constraint will be enforced to maintain flows below the limit
EIM will coordinate with WECC’s Unscheduled Flow Mitigation Procedure (UFMP) and Enhanced Curtailment Calculator (ECC)
If EIM Entity initiates UFMP, CAISO will reflect the affected schedules in EIM dispatch, and enforce constraint limits as requested by RC.

18. EIM Entity identifies resource constraints to address reliability issues which cannot be modeled
CAISO will not issue exceptional dispatch instructions to EIM Entity resources
CAISO’s dispatch will reflect reliability constraint within EIM area until the base schedule can be updated
Any resource constraint for reliability will be settled at the EIM LMP

19. Publication of schedules
15-minute base schedules and energy schedules will be published to SCs through CAISO Market Results Interface (CMRI)
5-minute dispatch instructions will be communicated to the EIM Entity and the SCs
Net scheduled interchange will change every five minutes through the Dynamic Schedule to ensure AGC control accuracy for the CAISO and EIM Entity

20. Publication of prices and other information
Locational marginal prices for 15-minute market and RTD will be published on OASIS for all nodes and LAPs.
Binding transmission constraints and shadow prices will be published on OASIS
LMP marginal cost of congestion component reflects congestion contribution from binding network constraints
Additional market data that requires an NDA is published on CMRI

21. Ancillary service requirements
EIM Entity remains responsible for meeting ancillary services requirements per NERC and WECC, dispatching contingency reserves, and managing load reductions
Reserve sharing schedules
EIM Entity is responsible for their share of DCS compliance
EIM Entity deploys operating reserves and regulation in conformance with NERC, WECC, and reserve sharing group policies
If reserves are dispatched, they will be subject to EIM imbalance settlement until reflected in the base schedule
Capacity to meet reserve sharing obligations is included in the resource plans used for base schedules. The capacity is protected for dispatch through EIM.

22. EIM settlement
Instructed imbalance energy settled in two tiers at the relevant LMP:
15-minute instructed imbalance energy
5-minute instructed imbalance energy
Uninstructed imbalance energy treatment based upon meter granularity
Generation, participating load, and dynamic resources that are metered in 5-minute intervals settle at relevant interval LMP
Non-participating load settles at the volumetric hourly weighted average LMP for the LAP based upon the difference between the load forecast and the actual use
Allocation of uplift costs will track costs within EIM Entities and minimize comingled charges to the extent possible.

23. EIM accounting Unaccounted-for energy Inadvertent energy
Net energy delivered into UDC adjusted for service losses
EIM Entities need to define UFE service areas within footprint
Inadvertent energy
CAISO will maintain a dynamic schedule to track energy between EIM Entities and CAISO
The hourly energy will be updated on the e-Tag within 60 minutes of the end of the operating hour
EIM Entity responsible for tracking and administering payment for inadvertent energy via WECC process
Settlement metering is required for generators. Options:
CAISO Metered Entity
Scheduling Coordinator Metered Entity

24. EIM administration Administrative Costs Forecasting Services
Administrative rate if $0.19 per MWh volume as calculated by:
Generation = max (5% of gross generation, generation imbalance energy), plus
Load = max (5% gross load, load imbalance energy)
Startup costs equal $0.03 times an EIM Entity’s total annual energy usage
Forecasting Services
CAISO load forecast is included in Administrative Rate
VER forecasting available for $0.10 per MWh
Dispute resolution is through Customer Inquiry, Dispute and Information (CIDI)
Market monitoring provided by CAISO

25. Transmission Service
Since initial transfer capability between CAISO and PacifiCorp will be limited and as-available, initial design proposes no charge for transmission for EIM dispatch
EIM stakeholder process will continue discussion of transmission rate design for EIM transfers

26. CAISO is committed to ensuring EIM design will properly account for GHG costs
Entities that import energy to California have obligation to surrender compliance instruments to CARB
The net incremental transfer to CAISO from EIM will be tracked through e-Tag for dynamic schedules
The market optimization will consider GHG costs

27. Other design items
Parallel stakeholder initiative will address governance, with white paper published by August 13 for discussion starting at August 20 stakeholder meeting in Portland
Process for new EIM Entities:
Interested parties are encouraged to engage as early as possible
Future implementations may occur on an annual commitment cycle with month lead time, reflecting significant network modeling changes and alignment with CAISO’s spring and fall software release cycle
Implementation agreement filed with FERC will establish specific schedule and start-up payment ($0.03/MWh of annual energy)

28. Analysis of EIM Benefits

29. E3 quantified 4 benefits of PacifiCorp-CAISO EIM
Interregional dispatch savings, by realizing the efficiency of combined 5-minute dispatch, which would reduce “transactional friction” (e.g., transmission charges) and alleviate structural impediments currently preventing trade between the two systems;
Intraregional dispatch savings, by enabling PacifiCorp generators to be dispatched more efficiently through the ISO’s automated system (nodal dispatch software), including benefits from more efficient transmission utilization;
Reduced flexibility reserves, by aggregating the two systems’ load, wind, and solar variability and forecast errors; and
Reduced renewable energy curtailment, by allowing BAs to export or reduce imports of renewable generation when it would otherwise need to be curtailed. (GridView simulations first estimated economic imports to CAISO using projected solar, wind, & load profiles, then fixed the imports as a minimum and observed renewable curtailments using actual profiles.)

30. Interregional Dispatch and Flexibility Reserve Benefits: modeling approach used production simulation

31. * Intraregional Dispatch Savings
PacifiCorp 2017 savings = CAISO 2009 savings1 *
PAC 2017 peak load
CAISO 2009 peak load or
PacifiCorp 2017 savings =
$105 MM *
10,079 MW =
$23 MM yr
45,486 MW
Refer to Frank A. Wolak, 2011, “Measuring the Benefits of Greater Spatial Granularity in Short-Term Pricing in Wholesale

32. A range of assumptions were considered with focus on making low end conservative
Low and high range assumptions under low (100 MW), medium (400MW), and high (800MW) transfer cabability
Assumption
Low transfer capability
Medium transfer capability
High transfer capability
Low Range
High Range
Maximum hydropower contribution to contingency and flexibility reserves*
25%
12%
Share of intraregional dispatch savings achieved
10%
100%
Share of identified renewable energy curtailment avoided
*Percent of nameplate capacity for each project

33. Significant benefits observed using range of assumptions
Low and high range annual benefits (Million 2012$)
under low (100 MW), medium (400MW), and high (800MW) transfer capability
Benefit Category
Low transfer capability
Medium transfer capability
High transfer capability
Low Range
High Range
Interregional dispatch
$ 14.1 $ $ $ $ $
Intraregional dispatch $ $ $
Flexibility reserves $ $ $ $ $
Renewable curtailment $ $ $
Total benefits
$ 21.4 $ $
$ 102.8 $
$ 128.7

34. Low and high range annual benefits (million 2012$)
Conclusions:
Significant benefits for PacifiCorp and ISO exist under an EIM, based on conservative assumptions.
Higher range of potential benefits exist depending on transfer capability and operational conditions.
Low and high range annual benefits (million 2012$)

35. Attribution of EIM benefits to PacifiCorp in 2017
Low and high range benefits attributed to PacifCorp (Million 2012$)
under low (100 MW), medium (400MW), and high (800MW) transfer capability
Benefit Category
Low transfer capability
Medium transfer capability
High transfer capability
Low Range
High Range
Interregional dispatch $ $ $ $
Intraregional dispatch $ $
Flexibility reserves $ $ $ $ $ $
Renewable curtailment $
Total benefits $ $ $ $ $ $
Note: Attributed values may not match totals due to independent rounding.

36. Attribution of EIM benefits to CAISO in 2017
Low and high range benefits attributed to CAISO (Million 2012$)
under low (100 MW), medium (400MW), and high (800MW) transfer capability
Benefit Category
Low transfer capability
Medium transfer capability
High transfer capability
Low Range
High Range
Interregional dispatch $ $ $ $
Intraregional dispatch $
Flexibility reserves $ $ $ $ $ $
Renewable curtailment $ $
Total benefits $ $ $ $ $ $
Note: Attributed values may not match totals due to independent rounding.

37. Interregional dispatch savings assumptions
Benefit Category
Assumptions (conservative, moderate, aggressive)
Rationale
Interregional dispatch
Conservative- Moderate
E3 limited PacifiCorp-ISO transmission transfer capability in the low transfer capability scenario to 100 MW, which limited EIM benefits
E3 used hurdle rates to inhibit interregional trade in Benchmark Case (moderate assumption)
Hourly cost differences between natural gas-fired generators are understated in production simulation models due to the use of uniform heat rates assumptions and normalized system conditions; these models understated EIM benefits

38. Intraregional and intra-hour assumptions
Benefit Category
Assumptions (conservative, moderate, aggressive)
Rationale
Within hour dispatch
Conservative
Production simulation analysis modeled at hourly level, omitting potential benefits of sub-hourly dispatch (other studies indicate that these benefits could be substantial)
Intraregional dispatch
Conservative-Moderate
E3 calculated nodal dispatch savings by scaling estimated ISO peak load-normalized savings by PacifiCorp peak load (moderate assumption); E3 assumed only 10% of these savings materialize for low range (conservative assumption)

39. Flexibility reserve assumptions
Benefit Category
Assumptions (conservative, moderate, aggressive)
Rationale
Flexibility reserves
Conservative
E3 limited PacifiCorp-ISO transmission transfer capability in the low transfer capability scenario to 100 MW, which limited EIM benefits
E3 included operating cost only; no capacity cost savings are included, which limited EIM benefits
E3 allowed 25% of total hydropower capacity to contribute to flexibility reserves in the low range estimates, which limited EIM benefits
E3 did not require lock-down of dispatch 45 minutes prior to the operating hour, as done in other studies, which would have raised the quantity of reserves required and increased EIM benefits

40. Renewable curtailment assumptions
Benefit Category
Assumptions (conservative, moderate, aggressive)
Rationale
Renewable curtailment
Conservative
E3 did not evaluate renewable curtailment for PacifiCorp. Which limited EIM benefits
In low range estimate, e# assumed wind and solar not producing significant over- generation (conservative assumption)
Production simulation models understate the frequency with which low net load/high generation events occur due to their use of idealized operating assumptions; these models limit EIM benefits

41. Hurdle rates between PacifiCorp-ISO to reflect removal of impediments to trade under EIM
*No CO2-related hurdle rate is applied to ISO exports to PACW because CO2 permit cost under AB32 is
directly modeled in the dispatch for generators located inside California.

42. Gas prices based on prices used in long term procurement proceeding
(in 2012$/MMBtu)
Area
2017
PACE_ID
$3.99
PACE_UT
$3.81
PACE_WY
$3.95
PACW
$3.91
PG&E_BAY
$4.09
PG&E_VLY
SCE
$4.18
SDG&E
$3.96

43. Flexibility reserve assumptions

44. Flexibility reserve assumptions
10-minute flexibility reserves by transfer scenario, Standalone & EIM Cases
PacifiCorp-CAISO Transfer
Minimum Reserve Holdings (MW)
Standalone (no EIM)
2,011
100 MW, with EIM
1,932
400 MW, with EIM
1,687
800 MW, with EIM
1,583
10-minute flexibility reserve detail for 2017, Standalone Case (no EIM)
Area
Average Regulation Up (MW)
Average Load Follwing Up (MW)
PacifiCorp East
103
313
PacifiCorp West 45
146
PacifiCorp Combined
115
357
CAISO
276
1,128

45. 120 GWh curtailment potential based on comparison of two simulation runs:
First run (representing unit commitment based on forecasted needs), projected solar, wind, and load profiles were used to estimate economic imports into ISO.
Second run (representing real-time dispatch), actual solar, wind, and load profiles were used along with minimum import limits set to the level of economic imports from the first simulation.
Curtailment occurred in second run represents conservative estimate of renewable curtailment.

46. $90/MWh avoided cost of curtailment based on:
Renewable energy certificate (REC) value, assumed to be $50/MWh;
Production tax credit (PTC) value of $20/MWh; and
Avoided production cost of the thermal unit that an EIM enables to dispatch down, estimated to be $20/MWh.