Market Services Stakeholder Information Session November 26, 2014 Public

Market Services
Stakeholder Information Session
November 26, 2014
Public
Agenda
• Welcome
• Transmission Constraint Management Rule
• Amended Operating Reserve Rule
• Enabling Load to Provide Spinning Reserve
Refreshment Break
• Phase Two Wind Integration
• Energy Storage Initiative
• Intertie Restoration Initiative
– LSSi Contract Changes and RFP Process
– Operational Studies Updates
– Joint BC Hydro Study Update
• Summary and Q&A
2
Transmission Constraint Management
(TCM) Rule
Kevin Dawson
Director, Market Design
Transmission Constraint Management
• Commission Directives
• Transmission Constraint Rebalancing (TCR) and use of
Transmission Must-Run (TMR)
– Pricing
– Payments/Settlement
– Reporting
• Implementation
– Rule Changes
– Tariff
– Settlement
4
TCM Directives
• Commission Directives (Decision 2013-135, para 197)
– Direction 1: include principles of RTMR proposal
– Direction 2: increase use of TMR/Dispatch Down Service (DDS)
 Direction 3: monitor and report costs*
 Direction 4: timeline and process steps for consultation**
 Direction 5: timeline and process steps for implementation**
* AESO filed a cost report on June 16, 2013 per Directive 3
** Decision 2014-067 AESO complied with Directives 4 and 5
5
Direction 1 – Real-time TMR Principles
• Single clearing price for energy – unconstrained
• Costs of any generation re-dispatch to be based on offers in
the competitive energy market
• Cost recovery of generation re-dispatch to be recovered
through transmission tariff
• Reporting on information regarding constraints as close to
real time as possible
6
New TCM Proposal Overview
• Use TMR/DDS where possible
• Create new Transmission Constraint Rebalancing (TCR)
approach to address RTMR principles
– TCR refers to energy delivered to restore the energy balance
on the AIES downstream of the constraint after the system
controller has followed the sequence of measures to mitigate
the constraint (with TMR)
– Incremental energy dispatched for the purposes of TCR in
accordance with the energy market merit order
• Not used to set the pool price
• Costs recovered through transmission tariff
7
TCR Clearing Price and Payments
• Single clearing price for energy is established by the
intersection of the unconstrained supply and demand curves
• Any downstream incremental energy required to balance the
system is paid “as bid” based on their offer prices in EMMO
• TMR as used is paid at contract or tariff rates
• No constrained down payments for “lost opportunity”
8
Energy Market Payments
• All energy dispatched is paid the pool price which in the case
of TCM (constraints) is set at the unconstrained price
• Any energy dispatch in blocks for TCR (rebalancing) is paid
as net to the clearing price (as bid prices and net volumes)
– TCR blocks paid greater of the pool price and their offer
(i.e., as bid) for the volumes required for rebalancing
– Payment rules outlined in subsection 7 of Revised Financial
Settlement Rule to stipulate these calculations
9
TCM Costs – TMR and TCR
• Any TMR used to address congestion will be recovered as it
is today through the tariff assigned to rate DTS and FTS
(Fort Nelson)
• Any TCR costs will be recovered through a “constraint
mitigation charge” for costs resulting from energy market
offers for system rebalancing above the unconstrained price
– The cost of generation re-dispatch for TCM will be recovered
through Rate DTS and Rate FTS as a separate charge
– Tariff changes will be submitted as part of the AESO’s next
tariff application
10
TCM Reporting
• The AESO will publish as near to real time as possible
information on regional constraints and costs involved
• The AESO will monitor and publicly report these costs on an
annual basis
– Volumes and dollar impacts
11
Use of TMR
• Increase the use of TMR/DDS in an effort to minimize the
price distortion in the market
– First use contracted TMR
– Then may use non-contracted TMR
• Daily/weekly forecast of constraints including identification of
TMR that may be effective
• Certain constraints that arise in real-time cannot be
effectively restored with contracted TMR
12
Implementation and Next Steps
• Rule Changes (expedited filing for TBD implementation date)
– Revised Financial Settlement Rules
– Revised Financial Default and Remedies Rules
– Revised Pricing Rule
– Revised Limited Markets Rule
• Tariff Changes (to follow in next tariff filing)
– Costs of generation re-dispatch
• Systems Changes (for Q4 2015)
– Unconstrained merit order/constrained merit order
– Settlement changes
13
Thank you
Questions?
Amended Operating Reserve Rule
Changes to Directive Tolerance Requirements
Will Chow
Market Implementation Analyst
Background
• 2013 filing of Operating Reserve (OR) Rules
– Transition of Authoritative Document (TOAD) exercise
• Objection filed to the original filing
– Stakeholders raised concerns about the operating reserve
directive tolerances for supplemental and spinning reserve
• Filing was postponed
– The AESO committed to reviewing the operating reserve
directive tolerances with market participants
16
Working Group/Consultation
• Stakeholder working groups held in Q1/Q2 of 2014
– The AESO engaged interveners in the 2013 objection
– Participants in the working group provided valuable input and
feedback to the AESO
• Update paper was posted in June 2014
– Addressed the direction that the AESO is taking regarding
operating reserve directive tolerances
– Stakeholders provided feedback that the AESO then
responded to
17
New Directive Tolerance Requirements
• Directive tolerance requirements are being relaxed
• Providers of spinning and supplemental reserve must adhere
to requirements over three time periods:
– T0-Tx: The directed unit has up to 10 minutes to reach the
directed OR MW volume. Note that the unit may reach this
level before T10.
– Tx-T15: The directed unit must provide, on average, the
directed MW volume until 15 minutes after receiving the OR
directive. Note that this time, at a minimum, will be 5 minutes
but may be greater.
– T15+: Energy market tolerances apply to the unit whereby a
pool asset must not vary the average MW it delivers from a
generating source asset in any 10 minute period from the
directive MW by more than the allowable dispatch variance.
18
Amended OR Rules
Proposed OR Directive Tolerance Requirements
Real Power
Level of OR
Provider
(MW)
Directed
Amount
Allowable dispatch
variance (same as
energy market)
Directive issued
5 minutes
10 minutes
15 minutes
20 minutes
19
Current Filing Schedule
• Letter of Notice issued on September 4, 2014
– Seeking stakeholder comments on the Amended Operating
Reserve Rules
– Feedback was received from stakeholders on
September 19, 2014
– AESO replies were posted on October 30, 2014
• Notice of Correction issued on November 13, 2014
– AESO identified a drafting error inconsistent with previous
consultation
• New filing timeline
– Filing of Amended Operating Reserve Rules with AUC on
December 1, 2014
– Proposed effective date of December 18, 2014
20
Thank you
Questions?
Enabling Load to Provide Spinning Reserve
David Michaud
Senior Market Implementation Specialist
Context
• New standards include load as a reserve type allowed to
provide spinning reserve1
– WECC Standard BAL-STD-002-0
– Alberta Reliability Standard BAL-002-WECC-AB-2
• Loads already provide supplemental reserve
• This initiative enhances load participation in the Alberta
power market by enabling non-aggregated load to provide
spinning reserve
– Non-aggregated load refers to a single load or other
device with a frequency responsive control system
equivalent to a governor system used by generators
1
Contingency reserves are the generation and load capacity available within a short duration to replace an unexpected loss of supply
23
Non-Aggregated Loads Providing Spinning
Reserve – Implementation Timeline
Item
Date
IT System Changes
Will be completed on
November 26, 2014
• Revision of spinning
reserve technical
requirements
(proposed ISO Rule 205.5)
Planned to be filed with the
AUC on December 1, 2014
with an expected effective
date of December 18, 2014
• Revision of SCADA
Technical and Operating
Requirements
(existing ISO Rule 502.8)
• Revision of definitions
• “spinning reserve”
• “supplemental reserve”
• “governor or governor
system”
24
How Spinning Reserve and Supplemental
Reserve Differ From One Another
• Providers of spinning reserve must be immediately and
automatically responsive to frequency deviations through a
governor or control system with specific characteristics
– 10 MW minimum
• Supplemental reserve:
– No requirement to be synchronized to the grid
– No requirement to be responsive to frequency deviations
– Can be provided by aggregated and non-aggregated
generators and load
– 5 MW minimum
25
Will Aggregated Load be Enabled to
Provide Spinning Reserve?
• We will consider enabling aggregated load and generation
located “within the fence” (not dispersed geographically)
– If deemed viable from a technical perspective, then spinning
reserve technical requirements would be revised to ensure a
governor or control system shared by multiple loads or
generators would act in the same manner as a governor or
control system for a single device
– This would help enhance market participation by both loads
and generators
26
Will Aggregated Load be Enabled to
Provide Spinning Reserve?
• At this time, geographically dispersed loads and generation
will not be enabled to provide spinning reserve
– In the future we will consider whether numerous small
geographically separated generators or loads could ensure
required governor or control system action occurs
27
Thank you
Questions?
Refreshment Break
Phase Two Wind Integration
Jacques Duchesne, P. Eng.
Program Manager, Wind Integration
Wind Power Is Growing
• 1,434 MW (9%) of transmission-connected wind generation
• BlackSpring Ridge wind farm (300 MW) and Oldman River 2
(46 MW) came on line in Q2 2014
• Over 2,400 MW of additional wind generation interest in the
project list (16 projects)
31
Approach to Wind Integration
• Phase I - In Place
– Wind technical rule
– Forecasting
– Wind power management
• Phase II - In Progress
– Wind to participate in the energy market
• aka Wind Dispatch
32
Wind Participation in the Market (Dispatch)
• Pilot with 2 wind assets was successful
• Allows wind to actively participate in the market through
energy offers
• Rules and allowable dispatch variance (ADV) definition were
consulted on and filed with the AUC in September 2014
• Rules will be effective April 1, 2015
– Allows sufficient time for Preferential Sharing of Information
Agreement as per FEOC regulation for JV asset
• Easy to comply:
– Must remain within Allowable Dispatch Variance
– Wind farm must produce the lesser of potential or
in-merit energy
33
How does it work @ T-2 ?
• 2 hours before delivery, the wind farm must offer its
maximum capability (MC)
– They can remain a price taker by selecting a zero dollar
standing offer in ETS
• Like other generators, wind enters volume and price using
7 pairs in ETS
• All wind farms will have to comply with Outage Rule 306.5
and update their available capability (AC)
– 5 MW or greater
• All wind farms will have to provide the current and planned
AC for forecasting
34
How Does it Work in Real Time?
• Leverage on the potential MW from the Wind Technical
Requirements
– Potential MW is fed via SCADA
Wind Power
Management?
Supply
Surplus?
POTENTIAL
Transmission
Constraints?
In-merit?
DISPATCH LOWEST VALUE
35
Allowable Dispatch Variance
• The AESO is already receiving potential MW
– No need to restate because wind production is decreasing
• Wind assets are in compliance as long as they produce their
in-merit energy or their potential if potential is less
• If potential is greater than in-merit, the asset must cap itself
to in-merit volume
• +/- 5 MW for asset with MC 200 MW or less
• +/- 10 MW for asset with MC greater than 200 MW
36
Thank you
Questions?
Energy Storage Initiative
Jacques Duchesne, P. Eng.
Program Manager, Wind Integration
Storage Background
• Alberta Innovates Technology Futures (AITF) conducted
economic studies
– Studies raised market participant interests
– Study showed bulk storage already has positive net present
value (NPV)
• 2 storage projects are in the AESO connection queue
– 150 MW Compressed Air
– 14 MW Battery
39
Alberta Electricity Price Volatility
Monthly Average Pool Price
$200
$180
Monthly Pool Price ($/MWh)
$160
$140
$120
$100
$80
$60
$40
$20
$0
Average pool price
On- and off-peak average pool price
Annual Average Pool Price:
2009- $48/MWh, 2010- $51/MWh, 2011- $76/MWh, 2012- $64/MWh, 2013- $80/MWh
40
What is the AESO doing?
• AESO launched energy storage initiative in September 2012
– June 2013:
Released Issue Paper
– Sept-Oct 2013: Industry Workgroup
– May 2014:
Issued Discussion Paper
• Priorities:
– Technical requirements to connect
– Tariff treatment
– Technical requirements for the provision of OR
41
Technical Requirements to Connect
• As opposed to wind, storage technology can take many
forms
• Focus first on battery because of uniqueness
– Compressed air or pumped hydro are similar to other forms of
generator or load (electric compressor, gas turbine or hydro
generator)
• Issued Recommendation Paper in October 2013 and
conducted workgroup sessions
– AESO posted replies to stakeholder comments in April 2014
• Technical rule and operating rule will be filed next year
42
Tariff Treatment
• Based on stakeholder feedback received on the Discussion
Paper, the AESO is investigating whether storage could be
utilized as a transmission asset
• For storage participating in energy and ancillary service
markets, a cost causation study may be helpful in exploring
the appropriate transmission system cost allocation for
storage
– Further examination of potential dispatch profiles of storage
facilities
– Potential impact on the transmission system at different levels
(bulk system, regional system and point of delivery)
– Information gained could be utilized in the development of
rate options
43
Storage and Operating Reserve
• The AESO has completed a technical examination of the
impact of reducing the minimum size for regulating reserves
(15 MW range)
– Recommendation pending
• Entered into agreement with NRC to assess performance of
current regulating reserve product and supply mix
– Not a compliance exercise
– What is the effectiveness of current regulating reserve at
correcting Area Control Error (ACE)?
– What if some technical requirements were changed?
– What if some storage technologies were introduced?
– Target June 2015 completion
44
Storage Recommendation Paper
• Target end of 2014 or early 2015
• Will provide some conclusions plus a road map of additional
work to further advance the priority areas
– Expectations of information gained from NRC study and next
steps stemming from this
– Plans for additional analysis to guide tariff treatment
– Opportunities for additional stakeholder involvement
• Storage initiative is complex and interconnected with several
other current or future AESO initiatives
45
Thank you
Questions?
Intertie Restoration Initiative
Load Shed Service for Import (LSSi)
Contract Changes and RFP Process
Ruppa Minhas
Senior Commercial Analyst
Current Contracts and RFP Process
• Current agreements extended to June 30, 2015
• RFP to be published on MERX: www.merx.com week of
December 8, 2014
• Agreements resulting from RFP effective July 1, 2015
for a 3-year term
49
Contract Changes – RFP
• Loads must be able to be manually tripped by the System
Controller (most existing contracts have this provision
already)
– Providers will have 10 minutes to trip armed load from the time
the Trip signal is sent by the AESO through SCADA
– Used if there is an intertie trip and the system frequency does
not drop below 59.5 Hz, or an automatic trip fails to occur when
system frequency drops to 59.5 Hz
• Remove availability payment when LSSi would not be armed
to enable increased import capability
– Remove the availability payment if the planned or unplanned
outages for both 1201L and MATL are included in the AESO’s
Approved Outages Report
50
Contract Changes – RFP
• Revising the tolerance band within which the LSSi volume is
allowed to deviate from the dispatch
– Lower dispatch tolerance of 95% maintained to ensure that
armed LSSi has the minimum expected effect on arresting
frequency decline
– Increase upper band to 150% of armed load
• Clarity in Compliance
– Maintain 3 violations as in current contract
– Providers will have the option to submit a waiver to the AESO
– AESO will assess the contract non-compliance event to
determine whether the violation is eligible to be waived
51
Contract Changes – RFP
• Arming Price changes
– Providers will have the option to submit monthly arming price
changes, capped at the initially submitted RFP contract price
52
Thank you
Questions?
Operational Studies and
AESO/BC Hydro Joint Planning Study Update
Dilhan Rodrigo
Program Manager, Interties
Intertie Transfer Limit Changes – 2014
• January 30, 2014
– BC winter import total transfer capability (TTC) increased from
765 MW to 830 MW
– BC winter import TTC increased for certain system conditions
(Langdon SVC OOS, 936L/937L OOS, N-S 240 kV line OOS),
from a range of about 450 – 550 MW, to 565 – 615 MW
– Similar increases were made to the combined BC/MATL
winter import system operating limit (SOL)
– LSSi table expanded to reflect increased import levels and
Alberta Internal Load (AIL) levels
55
Intertie Transfer Limit Changes – 2014
• May 1, 2014
– BC summer import TTC table was added
• Previously there was just one table for both summer and winter
seasons
– Limits are similar but slightly lower than winter limits due to
lower summer facility ratings
– Similar increases were made to the combined BC/MATL
summer import SOL
56
Intertie Transfer Limit Changes – 2014
• November 1, 2014
– BC winter export TTC was updated for system normal
conditions
– The constraint to export TTC under higher Alberta load
conditions was removed, and the export TTC was increased to
800 MW
– Similar increases were made to the combined BC/MATL
winter export SOL
• December 11, 2014 (planned)
– A comprehensive off-nominal frequency study has been
completed resulting in changes to LSSi arming requirements
– The updated ID with the revised LSSi table will be posted soon
57
Next Steps in 2015
• A comprehensive review of all summer limits is currently
being conducted
• The operation planning study includes all transmission facility
changes that are planned to be in service in the near future,
up to (but not including) the Chapel Rock project ISD
– Summer limit changes planned to be implemented after certain
key transmission facilities are in-service (expected Q3 2015)
• 936L/937L bypass from Langdon (Crossings) to East Calgary
• 1064L and 1065L from Langdon to Janet
• A comprehensive review of the winter limits will be initiated
after the summer limit study is completed
– Plan to have the updated winter limits implemented in Q4 2015
58
Background on Joint BCH Planning Study
• The joint planning study commenced in Q3 2013
• AESO and BCH agreed on base cases and assumptions
• Study cases included:
– 2014
– 2017 without Chapel Rock
– 2017 with Chapel Rock
– 2022 with Chapel Rock
– At various AB-BC, AB-MT, BC-US, and Alberta wind
generation levels
• Detailed BC and AIES models were then merged with the
corresponding WECC models
59
Update on Joint BCH Planning Study
• BCH performed study for BC contingency scenarios and
analyzed results
• AESO performed study for AIES contingency scenarios,
analyzed results
• Study results were reviewed jointly
• Constraints to restoring AB-BC flows to full path rating were
identified
– 1,200 MW import from BC to AB
– 1,000 MW export from AB to BC
– Simultaneous with other intertie flows (i.e. MATL at full)
60
Update on Joint BCH Planning Study
• Potential mitigation measures were identified to address the
constraints
• Study performed with the mitigation measures
• BCH and AESO have prepared separate detailed study
reports
• Draft reports were exchanged for review and comment
• Target for finalizing study reports is December 2014
• Based on these study results and other AESO analysis, the
AESO will update its Intertie Restoration plan and expects to
share with stakeholders in Q1 2015
61
Thank you
Questions?
Key Priorities for 2015
• TCM Implementation
• Competitive Process
• Market Systems Replacement
• Intertie Restoration
• Storage
• OR Product Assessment
• Load Participation
63
General Q&A