Transcript MODULE 5_Market and System Operations_ Tx and Dx Outlook

MODULE 5:
Market and System Operations & Transmission
and Distribution Outlook
August 2016
Overview

Over the next 20 years, several key factors and changes, including policy decisions related to
integration of new resources and demand growth (e.g., Ontario’s Climate Change Action Plan),
increased adoption of distributed energy resources, retirement and refurbishment of major
generation facilities, and end-of-life of transmission facilities, are expected to have an impact on
the reliability and operability of the transmission and distribution system in Ontario.

New investments, tools and measures may be required to respond to the evolving circumstances
and to ensure the continued reliability and operability of the transmission and distribution system.

There may be opportunities to maximize the use of existing assets and to align new investments
with Provincial Policy Statement, which requires the consideration of existing sites and joint-use
linear infrastructure corridors as part of infrastructure planning and development.

This module examines key planning and operational considerations, including:
Potential transmission investments to facilitate integration of new resources
Managing the impact of electrification on the regional transmission and distribution system
Integration of DER and its impact on the transmission and distribution system
Opportunities to align end of life replacements with evolving priorities
Preparedness for extreme events
Tools and measures to manage changing operating conditions
2
POTENTIAL INVESTMENTS TO
FACILITATE INTEGRATION OF
NEW RESOURCES
3
Limited Remaining Transmission Capacity to Connect Resources
•
Over the past decade, Ontario has focused on maximizing the use of the existing system. Over 7 GW
of renewable energy resources have been added in Ontario since 2005 without major system
expansion.
•
However, most of Ontario’s electricity system is at or nearing its capacity to connect additional
resources.
-
Much of Ontario’s remaining undeveloped renewable resource potential is located in areas of limited
transmission capacity, either due to system constraints or by being located far from the existing grid
-
While non-renewable resources, such as gas or nuclear generation, have more flexibility in terms of where they
can be located, these resources would likely be sited at existing generation sites in southern Ontario where
there is limited remaining transmission capacity.
4
Major system reinforcements will be required to enable new
resources in various parts of Ontario
•
Should Ontario pursue a significant amount of new resources, major system reinforcements would
be required to deliver these resources to the various load centres across the province. The type,
location, and magnitude of resource development will drive the transmission investment
requirements.
•
Commitment of transmission facilities must be made with sufficient lead time to ensure they are
available when needed.
–
The lead time for new major transmission projects are usually in the order of 7 to 9 years, but some can
involve longer timescales depending on the complexity of the project and the land-use and community
impact.
–
For example, even with an accelerated timeline and a well-defined scope, the Bruce to Milton transmission
project required a lead time of 7 years.
5
Transmission to Enable Resources in Northern Ontario
A large amount of Ontario’s remaining renewable
resource potential is located in Northern Ontario:
Albany/Moose River Basin, the Sault and Algoma area,
and east Nipigon area (up to 4,000 MW).
North-South Reinforcements: To deliver power from
these resources to load centres in southern Ontario,
the major transmission pathway between Sudbury and
GTA would need to be reinforced.
Below are some North-South reinforcements options
Potential Option
Incremental
Capacity
Land Use Impact
Convert the existing 500kV
transmission lines to two HVDC
Bipoles
1,000-1,500 MW
Utlizes existing right of way
Install a new HVDC bipole
2,000 MW
Requires a new right of way
6
Transmission to Enable Resources in Northern Ontario (Con’t)
In addition, a number of transmission upgrades would be required within Northern Ontario to connect new resources and to
enable power to be transferred within the region. Below are some examples:
Sudbury North Reinforcements: Large hydroelectric
development in Albany/Moose River Basin, biomass and
wind developments would trigger the need for
reinforcements of the Sudbury North transmission
system
Sudbury West Reinforcements: To incorporate large
wind, solar and biomass along the eastern shore of Lake
Superior and the Northwest, reinforcements of the West
of Sudbury and East Lake Superior transmission system
would be required.
Enabling Facilities and Connection Lines: New
connection lines between the Northwest transmission
system and generation facilities would be required,
depending on the location of the resource potential.
There is limited information on resource potential in Northern Ontario beyond what has already been identified in
Albany/Moose River Basin, the east Nipigon Sault and Algoma areas (up to 4000 MW). Transmission investments to
connect resources beyond this level are not known at this time as it is dependent on the size, type and locations of these
potential resources.
7
Transmission to Enable Resources in Southern Ontario
If significant resources are developed, they will likely be located at existing generation sites in Southern Ontario to leverage
existing facilities and to minimize the land use impact. Many of these sites have limited transmission capacity.
Reinforcements would be required to enable these resources in Southern Ontario. Below are some examples:
Bowmanville to GTA reinforcements: The
incorporation of additional resources sited East of
Toronto would trigger the need for new 500 kV
double circuit lines between Bowmanville and GTA.
West of London Reinforcements: Significant
developments of resources in the Sarnia-Lambton
area would require reinforcements of the
transmission system between Sarnia and London
Enabling Facilities: Enabling facilities, such as
autotransformers and connection lines, could be
built to enable some resources in the Southwest
(e.g., 500 MW of renewable resources) should it be
required.
8
Transmission to Facilitate Firm Capacity Imports from Quebec /
Newfoundland
The existing system in eastern Ontario and interties cannot accommodate a large amount of firm imports from
Quebec/Newfoundland.
To facilitate any potential large (i.e. more than 1,000 MW)
firm import capacity deal from Quebec/Newfoundland,
major system reinforcements in eastern Ontario would be
required.
Reinforcements would depend on the firm imports levels:
 For 2,000 MW of firm capacity import, a new HVDC line
from Quebec to Lennox would be required.
 For 4,000 MW of firm capacity import, a second new
HVDC line from Quebec to GTA would be required.
9
Transmission to Facilitate Firm Capacity Imports from Manitoba
The existing northern Ontario electrical system cannot accommodate large firm imports from Manitoba to serve southern
Ontario load, as there are a number of significant bottlenecks along the pathways from Kenora to the GTA area.
Any import delivery to the GTA would require
significant upgrades to the Ontario transmission
system.
Transmission reinforcements would vary
depending on the firm import level. Below are a
few examples:
• For 300-500 MW of firm capacity imports, a
number of transmission reinforcements would
required to alleviate constraints within Northern
Ontario, including Sudbury West
Reinforcements, North-South Reinforcements
and reinforcements in Northwestern Ontario.
Reinforcements of intertie between Ontario and
Manitoba may also be required.
• For 1,000-2,000 MW of firm capacity imports, a
new 1,700km HVDC line from Manitoba to the
GTA area would be required.
10
INTEGRATION OF DISTRIBUTED
ENERGY RESOURCES AND ITS
IMPACT ON THE TRANSMISSION
AND DISTRIBUTION SYSTEM
11
Increased Penetration of DERs
As shown below, the installed capacity of DERs has increased by about 2000 MW over
the past five years.
12
Data for Slide 12: Installed capacity of DERs (2010-2015)
Year
2010
2011
2012
2013
2014
2015
DER – Installed Capacity (MW)
3,764
4,049
4,339
4,779
5,570
5,837
13
DER and its impact on Transmission and Distribution system
The increased penetration of DERs could have an impact on the distribution and transmission system.
Traditionally, distribution and transmission system have been designed to deliver power one way to loads.
Increasing levels of distributed energy resources can lead to bi-directional power flows that the electricity
system was not initially designed to accommodate. This can lead to operating and safety concerns.
The total amount of DERs that can be integrated into the distribution system can depend on technical
constraints on the transmission and distribution equipment. Some examples of technical constraints
include:







Short circuit contribution levels beyond the capability of existing equipment or established codes
Voltage and VAR regulation
Power quality (Harmonics, Flicker, DC Injection)
Unintentional islanding
Protection and control system design and coordination (fault protection, reclosers, etc.)
Equipment grounding
Controllability of DERS, and load and generation imbalances
Depending on the nature of the constraints, investments in the transmission and distribution system may
be required to facilitate the integration of distributed energy resources.
14
MANAGING THE IMPACT OF
ELECTRIFICATION ON THE
REGIONAL TRANSMISSION AND
DISTRIBUTION SYSTEM
15
Managing the Impact of Electrification on Regional Transmission and
Distribution system
At the regional level, the integration of EVs and electrification of mass public transit, and other forms of fuel
switching, such as shifting from natural gas to electric-power heat pumps, could increase peak demand
requirements and have an impact on the adequacy and reliability of the regional transmission and
distribution systems, especially in urban centres.
In addition, electrification can alter the profile of the demand and could impact the needs and solutions at
the distribution and regional level. Transmitters, the IESO and LDCs are looking at ways to help manage
and address these potential implications. Some examples include:
•
The long-term implications of mass transit electrification will need to be considered as part of the
regional planning process, especially in the GTA and surrounding areas and other urban centres.
Investments to accommodate Go Transit electric train conversion, and the Eglinton Crosstown LRT
project in Toronto.
•
To manage the growth in personal EVs, utilities may need to adapt to the demands placed on their
systems from EV charging facilities to effectively manage how and when customers charge their
vehicles. Some local utilities have already undertaken analysis of their systems using smart metering
data to determine the potential impact that high saturation of EVs will have on their system, and what
mitigating measures can be taken to manage emerging needs in the most cost-effective manner
16
OPPORTUNITIES TO ALIGN
END-OF-LIFE REPLACEMENTS
WITH EVOLVING PRIORITIES
17
Transmission Infrastructure End-of-Life
A substantial proportion of Ontario’s transmission infrastructure will reach its end-of-life in the
coming years.
For example, the expected service life of a transformer, which is a major component of a transformer
station, is about 60 years. Given the current demographics of the transformer fleet shown below, the
number of transformers beyond their expected service life will increase significantly over the 20 year
planning period.
Demographics of Ontario’s Transformer Fleet - 2015/2016
Source: Hydro One Networks, 2015-2016 Rate Application
A similar trend is expected for other transmission infrastructures, such as key lines, switching and station
facilities.
18
Better Alignment of End-of-Life Investments with Evolving Priorities
Transmission assets reaching end of life have typically been replaced with assets of equivalent capacity and specification.
This “like for like” approach has been applied most commonly in circumstances where minimal change was anticipated to
the supply and demand outlook.
However, where major change is anticipated, such an approach may not be appropriate. For example, in areas where
demand is projected to flatten or decline, like for like replacement of transmission assets commissioned decades ago may
lead to asset underutilization.
The need to replace aging transmission assets will present opportunities to better align investments with evolving power
system priorities, including issues and opportunities related to bulk system operability, bulk system resilience, customer
reliability expectations, demand forecast uncertainties and integration of distributed energy resources. For example:

Up-size equipment in areas with additional capacity needs to support growth or to integrate new resources

Downsizing or even removing equipment that is no longer required

Enhance or reconfigure assets for infrastructure hardening to improve system resilience
In general, greater integration between asset management, bulk and regional planning, and planning for extreme events
can help minimize unnecessary investment, maximize the value of existing assets and new facilities, and ultimately
minimize cost impacts to Ontario’s ratepayers.
19
PREPAREDNESS FOR EXTREME
EVENTS
20
Preparedness for Extreme Events
The province’s electricity system is planned and operated according to established reliability standards. As
such, customers in Ontario generally have access to a reliable supply of electricity.
 North American Electric Reliability Corporation (NERC) and Northeast Power Coordinating Council (NPCC) standards are
designed to ensure the security of interconnection systems
 Ontario Resources and Transmission Assessment Criteria (ORTAC) ensures reliability to local areas, including limiting the
impact of outages to customers when they do occur
 Power system equipment is designed to industry standards, such as those outlined by the Canadian Electricity Association
and the Canadian Standard Association
Major outages, including the 2003 Northeast Blackout, the 2013 Ice Storm and the 2013 flood in the western
GTA, have brought system resilience and customer service reliability concerns into the public spotlight. This
is an area of growing concern given the possibility of extreme events such as major storms and their impact
on the power system.
The consequences of extended power outages can include significant health and safety impacts for
customers, particularly vulnerable and aging populations, as well as economic impacts for customers and
society at large.
Over the next decade, it will be come increasingly important for Ontario to examine opportunities to improve
system resilience and to address concerns related to customer service reliability and expectations.
21
Impact of Extreme Events on the Power System
Extreme events could result in the stress or loss of many system components, with the number of impacted
elements exceeding the security standards that these systems are typically designed to endure. For example:
Extreme Weather Associated with Climate Change
Recent climatology studies indicate that due to climate change, some types of weather events will increase in
frequency and severity in the coming decades. Frequent and severe weather, such as wind, ice and flooding could
also cause widespread damage to equipment, resulting in prolonged power outages.
Age-related Deterioration of Transmission Reliability
As the transmission infrastructure ages, there may be an increased risk of power outages due to equipment
failures. Much of the replacement equipment or parts may be obsolete and cannot be easily acquired. The need to
schedule long outages to replace and refurbish aging equipment on major transmission corridors or stations could
have an impact on the electricity system.
Physical and Cyber Attack
Events involving physical security breaches of transformer stations, such as vandalism, terrorism and accidental
contact, can cause major outages. A cyber-attack on the electricity system can affect protection and control
facilities and reduce the ability of system operators to effectively operate the power system.
Areas where there is limited supply diversity (e.g., in rural or remote areas that rely on a single facility), or in areas
that are more vulnerable to power loss (e.g., in urban centres) are particularly susceptible to potential impact of
extreme events
22
Improving System Resilience
System resilience is the ability of the power system to anticipate, withstand, adapt to, and rapidly recover from an
extreme event by taking preventative actions to minimize the impact of outage and/or taking action to restore power and
mitigate impact during/after an event
A number of efforts already are underway in Ontario to improve system resilience:
 Operating policies and criteria require the IESO to take actions to improve system security under high risk conditions.
Protection systems are implemented, where appropriate and necessary, to help mitigate the risk related to extreme
events.
 The Ontario Electricity Emergency Plan and Ontario Power System Restoration Plan help coordinate electricity
emergency planning efforts and to restore the grid in a timely manner n the event of partial or complete blackout.
 The IESO conducts large-scale integrated emergency exercises and power system restoration workshops to build on
emergency preparedness and to assist market participants meet their obligations to test their emergency plans.
 The IESO partnered with the Ontario Climate Consortium to identify potential risks to transmission that could result from
changing climate patterns and to develop a framework/process for future climate adaptation studies.
Ontario will continue to assess system vulnerabilities and evaluate options for improving resilience by:
 Accounting for climate change in the development of extreme weather demand scenarios
 Designing and configuring facilities to better withstand extreme events
 Providing additional supply diversity, flexibility and security in a cost-effective manner and leveraging evolving
technologies and distributed energy resources as well as coordinating with distributed and transmission solutions
23
Customer Service Reliability and Performance Expectations
Service reliability and performance is measured based on customer exposure to power outages on the distribution
and transmission system, which is expressed in terms of frequency (i.e., number of outages a year) and duration (e.g.,
length of time before the power is restored). System Average Interruption Duration Index (SAIDI) and System Average
Interruption Frequency Index (SAIFI) and transmission customer delivery point standards are used to measure the
service reliability and performance of the electricity system in Ontario.
Given the growing concerns related to the impact of extreme events, customers have expressed interests in
exploring opportunities to improve service reliability performance.
 For example, since extreme events can have an impact on a large number of people and services in a high-density area,
urban areas may want higher levels of service reliability than provided for in the current service reliability standards.
The cost of improving service reliability varies depending on geography, the nature of the issue and the local
system configuration. Potential options could include enforcing higher minimum standards for redundancy,
undergrounding of overhead facilities and/or enhancing distributed energy resources, such as customer-owned
generation.
 For example, it can be very costly to provide the infrastructure needed to meet or improve service reliability in rural,
remote and sparsely populated areas.
As utilities and customers explore opportunities to improve service reliability and performances, the discussion of
cost responsibility and willingness to pay would be an important consideration.
 According to the OEB’s proposed “beneficiary pays” principle for cost-allocation, the responsibility to pay for higher
reliability would likely be borne by the customers in the area.
24
TOOLS AND MEASURES TO
MANAGE CHANGING
OPERATING CONDITIONS
25
Changing Operating Conditions
Over the planning period, changes such as increases in variable renewable generation and distributed
energy resources, nuclear decommissioning and refurbishments, aging and end-of-life transmission
facilities, and changing customer demand patterns could present new operating conditions and
challenges, such as:




System Voltage Performance Issues
System Congestion
Operating Variability and Uncertainty
Surplus Baseload Generation
Going forward, the IESO will continue to monitor, assess, and manage these issues. New facilities,
tools and/or measures will need to be in place to help maintain system reliability and operability.
26
Managing Voltage Performance Issues
System voltages are sensitive to changes in demand, system configuration, power flows on the transmission system,
and the availability of voltage regulating devices. The electricity system must have the ability to control voltage within
acceptable ranges defined by the reliability standards established for planning and operating the power system.
System voltages are sensitive to changes in demand, system configuration, power flows on the transmission system, and
the availability of voltage regulating devices.
In general, low power transfers (e.g., low grid demand could reduce power flow) on the transmission system can lead to
high voltage conditions while high power transfers can provide low voltage conditions.
27
Voltage Performance Issues Are Becoming More Prevalent
High voltage conditions are already emerging in the GTA, Northwest and Northeast and are expected to be
more severe and widespread over time due to evolving demand and supply conditions. Some examples are:

Flat demand forecast and increasing distributed energy resources are expected to increase the prevalence of low
grid demand conditions. Lower grid demand reduces power transfers across the transmission system, leading to
high voltage conditions.

Outages and retirement of large, transmission-connected generation facilities reduces the number of generators
available to help control voltages

The prevalence of variable renewable generation means that sizable amounts of generation output could abruptly
drop in a region, resulting in high voltage conditions or short-term spikes.
In other parts of the province, low voltage conditions are expected to arise

High forecast demand growth in the Ottawa area coupled with potential increased power transfers with Quebec
could lead to more frequent low voltages conditions and voltage instability in the event of a major outage.

In northeastern Ontario, the retirement of local generation facilities could create low voltage conditions that would
need to be managed.
28
Tools and Measures to Control System Voltage
New facilities, tools and/or measures will need to be in place to help manage voltage performance
issues across the province. This could include a combination of:

Traditional devices used to control voltages include shunt reactors (to reduce voltage) and
shunt capacitors (to increase voltage)

Devices such as static-VAR compensators (SVC), static synchronous compensators
(STATCOM), and synchronous condensers in circumstances where dynamic response or other
reactive power services are required

Generator voltage regulation control
29
Managing System Congestion
System congestion refers to instances during the operation of the power system when there is not enough transmission
capacity available to accommodate scheduled economic generation dispatch. This can result in some generators being
uneconomically constrained off while others have to be constrained on, resulting in higher costs for that hour of operation.
Over the long-term, a manageable level of congestion reflects an efficient utilization of transmission facilities.
In an effort to maximize the use of the existing system to accommodate new resources, many parts of the system are
becoming fully utilized and frequently congested, especially in Northern Ontario, West GTA and southwestern
Ontario.
The current system congestion level is still manageable. However, changes in demand and supply over the coming
decades will have additional impacts on system congestion:

Congestion is expected to increase as more variable and distributed energy resources come into service

The retirement of nuclear facilities in the GTA may increase flows from southwestern Ontario towards the GTA, resulting
in higher congestion in the southwest and western GTA areas.

If demand in the north declines, congestion levels could increase. On the other hand, demand growth could provide
congestion relief.
The IESO will continue to manage system congestion by:

Monitoring the system closely and exploring market designs and mechanisms to mitigate the its impacts

Carefully evaluating the impact of congestion and considering transmission expansion to enable further integration of
resources in future resource procurements
30
Variable Generation and Flexibility
Variable generation penetration is increasing causing system operating conditions to become increasingly variable and
uncertain. There is an underlying amount of uncertainty when scheduling variable generation due to the nature of the fuel
source (wind, sun, water etc.). The impact of this uncertainty increases as the amount of VG on the system is increased.
This will have an impact on real-time operations in terms of: load-following flexibility and potential surplus baseload
generation. With increased variable generation in our changing supply mix, the nature of load-following and Ontario’s
SBG profile will become increasingly variable and uncertain.
As total installed VG capacity increases,
so too does the impact (MW magnitude)
of forecast uncertainty
31
Managing Variability and Uncertainty
System operability is a measure of how well resources can reliably be coordinated to deliver power to loads in real-time,
in all expected conditions.
There is an increasing need to implement and utilize tools and measures to manage the variability and
uncertainty. Some examples are:

Remedial Action Schemes (RAS): refer to automatic protection systems designed to detect and correct
predetermined/abnormal system conditions. It is expected that additional RASs may be required in the future.

Control Devices: Flexible Alternating Current Transmission Systems (FACTS) deliver continuous response to system
conditions without need for operator control. It may become necessary to invest in additional FACTS.

System Load-Following Capability and Flexibility: This can be provided by real-time generator dispatch and
Operating Reserve (real-time market mechanisms) and frequency regulation (acquired through contracts). The IESO
is currently quantifying the need for additional flexibility in the 30 minute timeframe. This need is a direct result of realtime forecast errors increasing in magnitude (e.g. from increasing VG capacity online) and the need to more
frequently bring significant amounts of generation online with short notice. The solution may be to increase the
amount of ancillary services scheduled (regulation, OR), design a new ‘flexible load-following’ product, increase
intertie scheduling frequency or some combination of these.

Coordination with Distributed Energy Resources (DER): Several projects are currently in pilot stage, but DERs
may eventually play a larger role in helping manage the bulk system, including providing load-following and flexibility.
32
Surplus Baseload Generation (SBG)
Surplus Baseload Generation occurs when baseload generation* is higher than the Ontario Demand plus net
exports. This is a function of both the supply mix (more baseload units more potential SBG) as well as the demand
profile. To maintain a reliable and stable system, supply and demand must be kept in balance, requiring surplus
energy mitigation tactics.
Currently, most of Ontario’s surplus is managed economically through the market via exports to neighbouring jurisdictions.
The remaining SBG is managed by diverting water from hydro turbines (“hydro spill”); curtailing wind and solar; and
manoeuvering or shutting down units at Bruce NGS.
SBG as Percent of Ontario
Net Demand
SBG levels decline overtime as units from Pickering NGS retire and as units at Darlington and Bruce NGS are brought outof-service for refurbishment.
10%
8%
6%
4%
2%
0%
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
Year
* The expected baseload generation includes nuclear generation, baseload hydroelectric generation, and
intermittent generation such as wind and solar.
33
Data for Slide 33: SBG as Percent of Ontario Net Demand (Outlook B)
Year
Ontario SBG As Percent of Net Demand
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
9%
7%
6%
7%
6%
3%
3%
1%
4%
1%
1%
2%
2%
2%
2%
1%
2%
2%
3%
2%
34