24-Month Reliability Outlook (2011 – 2013)

24-Month Reliability Outlook
(2011 – 2013)
Table of Contents
24-Month Reliability Outlook 2011 – 2013
1
What is the 24-Month Reliability Outlook 2011 – 2013?
2
How Are We Doing?
3
Table 1: Summary of Transmission Constraint Events on AIES Cutplanes from 2007 to 2011
4
Table 2: Summary of Abnormal Operation Resulting in Transmission Path or Area Limit Reductions 2007 – 2011 in Hours per Year
4
Table 3: Table 3: Annual Total Constrained Down Generation (GWh)
5
Table 4: Number of Hours with Constrained Down Generation Entered by the System Controller
5
Expected Load Conditions
6
6
Figure 1: Yearly Actual and Forecast Summer and Winter Peak Loads
Supply Adequacy
7
Transmission Reliability
9
Transmission System Upgrades
11
Current Operating Conditions, Constraints and Potentially Adverse Conditions
12
13
Figure 2: Alberta Transmission Regions
Northwest Region
14
Northeast Region
15
Edmonton Region
17
Wabamun Lake/KEG and Edmonton/Fort Saskatchewan Area Bulk Transmission
18
Central Region
20
South Region
22
North-South Transmission
24
Alberta Intertie Capacity
25
Wind Integration
26
Demand Response
27
Highlights of the 24-Month Reliability Outlook
28
In Summary
29
24-Month Reliability Outlook
24-Month Reliability Outlook 2011 – 2013
Competitively priced and reliable electricity is essential to ensure Alberta’s
long-term growth and our continued high standard of living and prosperity.
The ability of Alberta’s electric system to meet future load growth depends on
continued access to sufficient generation and a robust transmission system.
As the Independent System Operator (ISO) in Alberta, the Alberta Electric System
Operator (AESO) leads the safe, reliable and economic planning and operation of Alberta’s
Interconnected Electric System (AIES). We also facilitate Alberta’s fair, efficient and openly
competitive wholesale electricity market which in 2011 had 164 participants and
approximately $8 billion in energy transactions.
Disclaimer
This 24-Month Reliability Outlook does not supersede or replace any ISO Rules, policies, procedures or
guidelines that are currently in effect. In the event of any conflict between the 24-Month Reliability Outlook
and the ISO Rules, policies, procedures or guidelines, the ISO Rules, policies, procedures or guidelines
shall prevail.
24-Month Reliability Outlook
PAGE 1
What is the 24-Month Reliability Outlook?
The AESO’s 24-Month Reliability Outlook provides a snapshot of the reliability of Alberta’s
electricity grid from the perspective of assessing our ability to meet electricity requirements
for the upcoming two-year period. This fourth annual edition of the Outlook covers the
two-year period from November 2011 to November 2013 and includes information on:
n
Expected load conditions, supply adequacy and transmission reliability of the
Alberta Interconnected Electric System
n
Transmission system upgrades being put in place to improve reliability
n
Current operating conditions, constraints and potentially adverse conditions that
could be avoided through coordinated maintenance plans for generation and
transmission facilities
n
Key market initiatives underway
Electric system reliability includes two components: supply adequacy and transmission
reliability. Supply adequacy means ensuring there is enough electric supply (generation)
to meet consumers’ demand for power. Transmission reliability is the ability to withstand
sudden disturbances or the unanticipated loss of facilities on the system. The AESO’s role
is to ensure the electric system is robust and ready to keep the lights on for Albertans 24/7.
PAGE 2
24-Month Reliability Outlook
How are we Doing?
Over the next two years, Alberta’s economy is expected to grow. According to The
Conference Board of Canada, Alberta’s economic growth, as measured by gross domestic
product (GDP) will increase by 4.1 per cent in 2012 and 3.6 per cent in 2013. Alberta is
expected to experience strong economic growth over the next five years and the long
term as investment in the oilsands spurs economic growth and job creation.
While new generation has kept pace with demand, tremendous growth over the last 10 years
has loaded the existing transmission system to its capacity. From 2009 to 2011, annual
energy growth was 2.6 per cent with strong growth in the oilsands sector and continued
growth in other industries.
Despite the slightly lower load growth rates in the last five years, parts of the electric system
continue to experience constraints that limit the ability to transmit power between various
locations in Alberta. In some parts of the province, constrained transmission lines can
strand electricity supply, making it unavailable to the market. In other areas constraints
occur when there is not enough transmission capacity to serve local load. For example:
n
Transmission must-run (TMR) services are required in the Rainbow Lake, northwest
Alberta and Calgary areas to maintain system reliability
n
Wind power generation constraints continue in the Southwest region–even with the
new 240 kilovolt (kV) developments in place–due to the need for additional
reinforcement of the transmission system in that area
n
Some regions (see Table 1) experience generation or load constraints when transmission
facilities are taken out of service for planned maintenance or by forced outages
Constraints on the electric system mean the impact of planned and forced outages
on transmission elements are becoming more obvious as indicated in Table 1 and 2.
The AESO is meeting this challenge through:
n
Planning transmission system development
n
Ongoing emphasis on coordination of planned outages
n
Developing and implementing reliability standards and operating tools and
procedures
n
Augmenting training and introducing new programs to help system operators
manage and maintain system reliability
n
Developing operating limits and tools in advance of each project stage of
transmission development
24-Month Reliability Outlook
PAGE 3
With the addition of new generation and continued demand growth, we expect the level of
congestion on the AIES to intensify until transmission reinforcement is completed. For the
AESO, timely approval and implementation of proposed transmission upgrade remain a
priority. At the end of 2011, total installed generation capacity on the Alberta system was
over 13,500 megawatts (MW) and the year-to-date winter season peak demand of 10,609
MW was reached on January 16, 2012.
Table 1 summarizes constraint events considered to form part of abnormal operating
conditions. Constraints can occur due to outages for planned maintenance, outages
planned for adding a new facility to the grid or forced outages of transmission elements.
Table 2 identifies the number of hours where abnormal operating conditions on different
cutplanes resulted in limited transfer capability.
1
Table 1: Summary of Transmission Constraint Events on AIES Cutplanes from 2007 to 2011
Cutplane or area
2007
2008
2009
2010
2011
Fort McMurray
328417
Keephills-Ellerslie-Genesee (KEG)
112
182
South of KEG (SOK)
31180
Southwest Wind
24 89 92105 72
Medicine Hat
0
28
2340
Airdrie Area
00061
South of Anderson
00016
Edmonton Area
00030
Table 2: Summary of Abnormal Operation Resulting in Transmission Path or Area Limit Reductions 2007 – 2011 (hours per year)
Reason for
Cutplane or area
2007
2008
2009
2010
2011
2011 Abnormal Operation
Fort McMurray
2
438438 769 990670 Planned and forced outages
Keephills-Ellerslie-
0
0
180
1,121
461
Primarily due to construction
Genesee (KEG)
outages required for
debottlenecking project
3
South of KEG (SOK)
526 613 591 1,4104,871 Planned and forced outages
Southwest Wind
100
800
968
1,487
1,223
Primarily during N-0 operation
Medicine Hat
0
500
443
507
561
Airdrie Area
000
118
755
Forced outages
South of Anderson
0
Edmonton Area
000
190
0
0
1,096
58
Planned and forced outages
Planned and forced outages
1
Most of the southwest wind constraints occurred during system normal operation; all other constraints occurred under abnormal operation.
2
Cutplane limit was reduced by 225-250 MW.
3
Cutplane limit was reduced by 550 MW for 338 hours and by 250-300 MW for 4,533 hours.
PAGE 4
24-Month Reliability Outlook
Constrained down generation (CDG) occurs when the amount of supply a generator can
transfer to load is limited by insufficient transmission capacity. Typically, the main sources
of constrained generation are constrained wind generation in the south, constraints to
Fort McMurray cogeneration, particularly when there are line outages in the northeast,
and constraints in the Keephills-Ellerslie-Genesee (KEG) area in response to transmission
upgrades in the most generation-concentrated region of the province.
During 2011, there was 142 GWh of CDG recorded by system controllers. Table 3 indicates
the recorded amount of generation constrained from 2008 to 2011, and Table 4 gives the
frequency of constraints on an annual basis. The constraints are categorized as either major
or typical. Major constraints include those constraints that would have a significant impact
on the market, for example, constraints to KEG area generators. Typical constraints are
those that occur on a regular basis, e.g., constraints to wind generation and Fort McMurray
area generation.
Table 3: Annual Total Constrained Down Generation (GWh)
Typical Constraint Types
Year
Total
CDG
Major
constraints
Total Typical
constraints
Wind
Fort
McMurray
Wind and 4
Fort McMurray Other
2008
295
274
21
20100
2009
55
16
39
27831
2010700
591
109
57
23
16
14
2011
142826013221511
4
Due to the way constraints are recorded by the system controller, there are periods when the AESO cannot definitively differentiate between the quantity
of generation constrained in Fort McMurray and the quantity of generation constrained from wind assets, when both sources of generation are constrained
at the same time.
Table 4: Number of Hours with Constrained Down Generation Entered by the System Controller
Year
Typical Constraint Types
Total
CDG
Major
constraints
Total Typical
constraints
Wind
Fort
McMurray
Wind and Fort McMurray Other
20081,516
1,009
507
481
25
1
20091,202
151
1,051
807
124
89
31
20103,295
1,651
1,644
1,078
321
121
124
20111,646
306
1,340
671
324
168
177
24-Month Reliability Outlook
PAGE 5
Expected Load Conditions
Alberta is expected to show steady economic growth over the long term. According to
the AESO’s Future Demand and Energy Outlook (2009–2029), average annual demand
is forecast to grow by 4.6 per cent for the next five years.
For the 2011 to 2012 winter season, the Alberta Internal Load (AIL) 5 winter peak demand
reached a high of 10,609 MW and the 2011 summer peak reached a record high of 9,552 MW.
Long-term load forecast winter peaks are 11,076 MW for 2012 – 2013 and 11,664 MW for
2013 – 2014. The forecast peak demand for summer 2012 is 10,408 MW and 10,941 MW for
the summer of 2013. For winter 2011 – 2012, the long-term load forecast anticipated a winter
peak of 10,577 MW, very close to the year-to-date peak of 10,609 MW. On a year-over-year
basis, Alberta’s total energy consumption for 2011 was 2.6 per cent higher than 2010.
Figure 1 shows AIL yearly actual and forecast peak loads from 2003 to 2013. Actual load
for the period November 2011 to November 2013 will depend on factors such as:
n
Weather conditions
n
Actions of price responsive load (approximately 250 MW)
n
New oilsands projects and associated industry coming on stream
Figure 1: Yearly Actual and Forecast Summer and Winter Peak Loads
12,000
11,500
Peak AIL (MW)
11,000
10,500
10,000
9,500
9,000
8,500
8,000
2003
Summer Peak
5
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
Winter Peak
Alberta Internal Load (AIL) is defined as the province’s total electricity consumption, including losses through
transmission and distribution, as well as load served by behind-the-fence generation.
PAGE 6
24-Month Reliability Outlook
Supply Adequacy
This section describes the ability of generation to supply total electrical demand and operating
reserve over the next two years. In Alberta, investor-driven market decisions will determine
the amount of generation added to the electricity system. Information on past development,
the status of current development, major supply increases or decreases and a summary of
supply adequacy results are provided.
Over the past few years, the province has seen significant investment in generation projects,
with 670 MW of capacity added in 2011, and 250 MW added in 2010.
In 2011, generation additions included the 450 MW Keephills 3 coal-fired plant and the
smaller 48 MW Weyerhaeuser and 15 MW University of Calgary facilities.
There is currently 208 MW of generation projects under construction that are expected to
connect to the grid by the end of 2013. Additional generation projects with the intention of
starting operations in the next two years (by January 2014) include approximately 1,263 MW
that have received Alberta Utilities Commission (AUC) power plant approval and an additional
1,590 MW that have been announced corporately or have applied for regulatory approval.
Cogeneration and wind generation facilities make up a large portion of the projects
expected to come online in the next two years. This investment is considered to be
adequate to meet the growth in demand and compensate for generation retirements.
On February 8, 2011, a notice of termination for destruction of the Sundance 1 and 2
coal-fired generation units was issued under the terms of the Sundance A Power Purchase
Arrangement after it was determined that these units could not be economically restored to
service. This determination has subsequently been disputed and the future of the two units
is unknown at this time. The units have currently been unavailable since December 2010.
Sundance 1 and 2 have a combined capacity of 576 MW which represents approximately
nine per cent of the Alberta coal fleet. While the removal of this capacity has created a
tighter supply-demand balance, the system has performed well since the units became
unavailable. Assessments of the coming 24 months have been performed and no supply
adequacy problems are expected at this time.
24-Month Reliability Outlook
PAGE 7
Overall generation capacity, as indicated by the forecast daily supply cushion, is adequate
to meet daily peak demand over the next two years. To ensure transmission congestion
does not strand a significant amount of generation, it will be necessary to continue to
closely coordinate generator and transmission outages.
The AESO has developed rules regarding generator outage cancellation and long-term
supply adequacy. These rules define the steps the AESO will take and issues that will be
considered when cancelling a planned outage in order to maintain supply adequacy and
reliable operation, as well as the means by which the AESO will monitor and report on the
long-term adequacy of the Alberta electric energy market.
The AESO performs a number of assessments to monitor the ability of supply to serve
firm demand and satisfy contingency requirements in the short to medium term (one day to
24 months) and the long term (up to five years). These assessments indicate supply reserve
margins will be adequate during the next two years but close coordination of generator and
transmission outages is required to ensure adequate supply and to avoid constraint events
during the real time operation. Further information on constraints events can be found at
www.aeso.ca
PAGE 8
24-Month Reliability Outlook
Transmission Reliability
Transmission reliability (sometimes referred to as operating reliability or system security)
is described as the ability of the electric system to withstand sudden disturbances or the
unanticipated failure of system elements.
In a May 2008 National Electricity Reliability Council (NERC) paper submitted as an
information filing to the Federal Energy Regulatory Commission (FERC), the following
definition was offered to describe an adequate level of reliability, drawing a distinction
between customer service reliability and transmission system reliability:
The System:
n
is controlled to stay within acceptable limits during normal conditions
n
performs acceptably after credible contingencies
n
limits the impact and scope of instability and cascading outages when they occur
n
facilities are protected from unacceptable damage by operating them within
facility ratings
n
integrity can be restored promptly if it is lost, and
n
has the ability to supply the aggregate electric power and energy requirements of
the electricity consumers at all times, taking into account scheduled and reasonably
expected unscheduled outages of system components
As it relates to reliability, risk is the likelihood that an event (i.e., an outage or change
in operating conditions) will reduce the reliability of the power system to the point that
consequences are unacceptable (e.g., equipment damage or cascading outages). Since
sudden disturbances or the unanticipated failure of system elements are unforeseen and
not preventable, the AESO needs to plan and operate the electric system so that when these
events occur, the effects are manageable and consequences are acceptable as defined in
the Alberta Reliability Standards and AESO Reliability Criteria. It is critical to effectively
manage risk to ensure the power system is operated reliably.
To do this, the AESO regularly performs operations planning studies to assess the operability
and reliability of the transmission system under a broad range of conditions. The AESO
uses the results to establish operating limits and procedures that protect generation and
transmission equipment from damage that could jeopardize reliability for weeks or even
months. Results are also used to support integration of new generation and transmission
facilities and to facilitate the coordination of outages.
24-Month Reliability Outlook
PAGE 9
Reliable system operation depends on a continuously connected and managed power system
with synchronized generation, transmission and load. System operators monitor the overall
reliability of the power system on a moment-by-moment basis by keeping flows within limits
while balancing supply with demand.
Another safeguard of Alberta’s electric system reliability is the AESO’s adherence to criteria
developed by the North American Electric Reliability Corporation (NERC) and the Western
Electricity Coordinating Council (WECC). The NERC/WECC reliability standards and criteria
are central to assessing the adequacy of the future transmission system. With an adequately
planned system and prudent operating criteria, we can operate the system reliably while
facilitating an open and competitive market. The AESO carries out studies using the NERC/
WECC reliability criteria on a regular basis.
The AESO has worked collaboratively with stakeholders over the last two years to create a
made-in-Alberta set of reliability standards that guide the operation of the province’s electric
system and contribute to maintaining and improving the reliability of the North American
electricity grid. Implementation of reliability standards in Alberta will continue through 2012.
The positive evaluation received by the AESO in the WECC audit completed in October 2011
is an endorsement of the AESO’s commitment to excellence in operations and safe, reliable
operation of the Alberta Interconnected Electric System.
PAGE 10
24-Month Reliability Outlook
Transmission System Upgrades
One of the AESO’s priorities remains timely approval and implementation of proposed
transmission upgrades in order to meet future electricity demand, interconnect generation,
satisfy reliability requirements and upgrade the power system in the best interest of Albertans.
These proposed upgrades include improving the transfer capacity of interties that connect
Alberta’s transmission system to the neighboring jurisdictions of Saskatchewan and British
Columbia, and connecting a new intertie to Montana. Alberta’s electric system reliability is
enhanced by these connections, which allow us to import power to meet peak demand in
the summer and winter and help alleviate power shortages by providing access to additional
back-up power in case of sudden equipment failure.
To keep pace with Alberta’s continued growth in load and generation and enhance reliability,
several transmission upgrades were completed in 2011. These include:
n
A new switching substation, Arcenciel 930s, with +/- 30 MVAr SVC and 30 MVAr
capacitor bank
n
A new 144 kV line, 7L133, from Sulphur Point 828s to High Level 786s
n
A new 7L113 144 kV line from Arcenciel 930S to Ring Creek 853S
n
Two new 144 kV lines, 7L122 & 7L93, from Arcenciel 930s to Rainbow Lake 791s
n
A new 33 MVAr capacitor bank at Brazeau 62s
n
A new 21 MVAr capacitor bank at Amoco Brazeau 358s
n
A new 27 MVAr capacitor bank at Cynthia 178s
n
A new 32.5 MVAr capacitor bank at Cold Creek 602s
n
Two new 672L and 673L 138 kV lines from Entwistle 235s to Violet Grove 283s
to replace 129L 69 kV line
n
A new phase shift transformer at Russell in the southwest
n
A 240 kV phase shift transformer at Keephills 320P
n
Edmonton Region debottlenecking project in progress
n
Milo switching station; converted two 240 kV three terminal lines to three two
terminal lines
n
The 100L 138 kV line from Brooks 121s to Tilley 498s converted to a new 666L line
from West Brooks 28s to Tilley 498s
24-Month Reliability Outlook
PAGE 11
Current Operating Conditions, Constraints
and Potentially Adverse Conditions
This section describes the operating conditions, limits and potentially adverse conditions
that might occur throughout the 2011– 2012 winter operating season and to end of the 2013
timeframe of the 24-Month Reliability Outlook.
Peak demand and thermal ratings6 of transmission equipment are higher in the winter
and lower in summer season. Planned maintenance on transmission and generating assets
generally happens in the summer. This often results in more stress on the transmission
system during the summer.
When the overall Alberta supply reserve margin is low, most generators are expected to be
in merit.7 High market prices for energy are likely to attract imports, which bring power into
the south central part of the transmission system. Higher winter thermal ratings and most
supply being in merit during peak periods should create an overall sufficient level of
transmission reliability for the winters of 2011 to 2012 and 2012 to 2013.
As system load continues to grow and generation develops in specific areas, the effects of
contingencies (sudden failures or outages on the system) become increasingly pronounced.
Close coordination of generator and transmission outages is required to ensure adequate
supply and avoid constraint events during real-time operation.
The AESO is meeting this challenge through transmission development and continued
emphasis on coordination of planned outages and developing enhanced operating tools,
real-time studies, procedures and training for our system controllers, and an ongoing
emphasis on comprehensive analysis and follow up should disturbances occur.
There continues to be immediate and significant operating challenges in the Northwest,
Northeast, Edmonton, Central and South regions of the province that require constraint
management and special operating procedures, use of Transmission must-run (TMR)
generation, remedial action schemes and coordination of transmission and generation
outages. These are described on the following pages.
6
Thermal ratings are the maximum amount of electrical current transmission facilities can conduct over a period
7
This means a designation applied to an asset dispatched by the system controller that qualifies the asset as eligible
of time without overheating and causing permanent damage or violating equipment safety margins.
to set the system marginal price.
PAGE 12
24-Month Reliability Outlook
Figure 2: Alberta Transmission Regions
Northeast
Northwest
JOSLYN CREEK AURORA
MUSKEG RIVER
D05
KINOSIS
WESLEY CREEK
BRINTNELL
WABASCA
LEISMER CONKLIN
MCMILLAN
CHRISTINA
LAKE
MITSUE
HEART LAKE
LITTLE SMOKY
MARGUERITE
LAKE
WHITEFISH LAKE
LOUISE CREEK
AMELIA
SAGITAWAH
LAMOUREUX
BICKERDIKE
KEEPHILLS
DEERLAND
Edmonton
BIGSTONE
BRAZEAU
WILLESDEN GREEN
CORDEL
NEVIS
METISKOW
PAINTEARTH
Central
EAST CROSSFIELD
CALGARY
ENERGY
BEDDINGTON
CENTRE
SHEERNESS
ANDERSON
WARE JUNCTION
EMPRESS
JENNER
WEST BROOKS
Existing transmission lines
Voltage
69/72 kV
138 kV
240 kV
500 kV
24-Month Reliability Outlook
PEIGAN
South
PAGE 13
Northwest Region
The Northwest region of Alberta is a geographically large area northwest of the City
of Edmonton. It is bordered by Fort McMurray and Athabasca to the east, Hinton and
Wabamun to the south, B.C. to the west, and the Northwest Territories to the north. While
this region represents approximately one-third of the area of the province, it represents only
one-tenth of total demand on the electric system.
The Northwest region includes the Rainbow Lake, High Level, Peace River, Grande Prairie,
High Prairie, Grande Cache, Valleyview, Fox Creek and Swan Hills planning areas but not
the Wabamun Lake area. It is connected to the Wabamun Lake area primarily through three
240 kV transmission lines and is connected to the Fort McMurray area through one 240 kV
transmission line. The Northwest region contains approximately 10 per cent of the provincial
peak load and is a net load area. Due to this imbalance, the region relies on transfer of power
from the Wabamun Lake and Fort McMurray areas. The AESO contracts TMR services so
that a minimum amount of generation stays online to ensure power transfers into the region
are kept within system operating limits.
Within the Northwest region, the Grande Prairie area also requires TMR to meet reliability
criteria as the area does not have sufficient local transmission capacity. The amount of
TMR services required depends on whether or not the power transfer to this area exceeds
specific limits.8 In addition, the Rainbow Lake area lacks sufficient transmission capacity
to support area load and TMR services are required all the time. The Northwest Alberta
Transmission Development Plan, approved August 21, 2006 by the AUC, was designed to
improve system reliability and eliminate reliance on TMR generation in this area. The project
is still under construction and expected to be completed by March 2013.
Since the approval of this transmission development on August 21, 2006, load in the Northwest
region has increased. Operational and long-term planning studies to evaluate the impact
of the load increase on the Northwest area system are underway to determine the need
for additional reinforcements or temporary TMR. These results will be published in 2012.
Transmission resources added or expected to be commissioned in the Northwest region
between 2011 and 2013 include:
n
Construction of two 144 kV lines, 7L109 and 7L122, from Rainbow Lake 791S
to Arcenciel 930S
n
Construction of -30/+50 MVAr synchronous condenser at Arcenciel 930s
These additions will improve area transfer capability and voltage control and reduce
the dependence of area load on TMR services.
8
Limits are based on transmission system conditions and the amount of base-loaded generation online in real time.
PAGE 14
24-Month Reliability Outlook
Northeast Region
The Northeast region of Alberta is bounded on the north by the Northwest Territories, on the
east by the Saskatchewan border, on the west by the Fifth Meridian, and on the south by the
Edmonton, Wetaskiwin, Vegreville and Lloydminster planning areas. The Northeast region
includes the Fort McMurray, Athabasca/Lac La Biche, Cold Lake and Fort Saskatchewan
planning areas.
The Northeast region is forecast to experience the greatest load growth of any region in
Alberta over the next 10 years. This is due in large part to growth in the oilsands, upgraders,
and related secondary service industries in the municipalities within the region.
Load in the Northeast region is predominantly industrial and makes up approximately
25 per cent of provincial peak load. The majority of the electrical load and generation in the
region is located in oilsands developments north of Fort McMurray and in Cold Lake and
Fort Saskatchewan. Generation in the region is mainly gas-fired cogeneration accounting
for 3,000 MW of Alberta’s total installed generation capacity.
The Fort McMurray area is connected to the transmission system by three 240 kV transmission
lines. The current transfer capability for outflow is 575 MW and inflow is 300 MW.
Historically, this area has outflow to the AIES most of the time; under typical operating
conditions, transfer outflow is approximately 300 MW. The area continues to experience
high load growth related to oilsands development.
The current transmission system does not have the capacity to supply the entire load of the
Fort McMurray area without support from local generation. However, a significant amount
of the area generation is baseload industrial cogeneration and, under normal operating
conditions, is adequate to support reliable operation. The AESO plans to install capacitor
banks of 260 MVAr to improve area inflow and outflow transfer capabilities and manage
voltage to help maintain reliability in the area.
The Fort McMurray area experienced real-time constraints eight times in 2009, 41 times in
2010 and seven times in 2011. Enhancing transfer capabilities into the area will be achieved
by adding more voltage support devices during the next two years. Longer-term plans
include the construction of 500 kV lines into this area.
24-Month Reliability Outlook
PAGE 15
The Cold Lake area has surplus generation and thermal constraints on the transmission
system that are managed through special protection schemes. On February 10, 2011, the
Alberta Utilities Commission approved the Central East Transmission Development (CETD)
Needs Identification Document (NID) for the Central East region (which includes development
in the Cold Lake area) that will address long-term transmission needs. The NID includes
construction of two 240 kV lines and a substation, both to be initially operated at 144 kV.
In addition, a number of existing 144 kV lines will be upgraded to a higher rating to alleviate
existing bottlenecks. The majority of the transmission system reinforcements are targeted
to be in service by the fourth quarter of 2012, but may be delayed into 2013. This
transmission system development will facilitate both projected load growth and the
connection of cogeneration facilities in the Cold Lake area. Due to the anticipated delays
of the transmission reinforcements coupled with load growth in the Cold Lake area, new
remedial action schemes (RAS) and operating policies and procedures (OPPs) are under
consideration as an interim solution for mitigating transmission constraints.
The load growth in the Northeast region during the last two years is causing constraint
on the Northeast planning cutplane in real time operation. Completion of the Heartland
Transmission Project is required to remove these constraints and support local demand
in the Heartland area, accommodate future demand in northeast Alberta including
Fort McMurray, and provide effective system integration for the Edmonton to Calgary
Transmission Reinforcement Project.
Transmission resources added or expected to be commissioned in the Northeast region
between 2011 and 2013 include:
n
260 MVAr capacitor bank additions to improve voltage management
n
A number of 240 kV, 240/138 kV substations and 144 kV lines in the Fort McMurray
area to connect new oilsands projects
PAGE 16
24-Month Reliability Outlook
Edmonton Region
The Edmonton region encompasses the City of Edmonton and includes the Wetaskiwin,
Wabamun and Edmonton planning areas. This region is the hub of Alberta’s electric system,
comprises over 20 per cent of provincial peak load and has 4,900 MW of Alberta’s
generation capacity. Most of the generation is baseload coal-fired power located around
Wabamun Lake and flows east and south with smaller amounts flowing north and west.
The transmission system in the Edmonton region has the capacity to serve firm load in the
region when all transmission elements are in service and baseload generation is online in
the Fort Saskatchewan area. The 138 kV system south and west of the City of Edmonton
is thermally constrained due to increased load in the area. During high load conditions,
Category B9 events may overload the 138 kV lines, creating a risk of the system not meeting
reliability criteria. When one transmission element is out of service due to planned or forced
outages, there are several local area constraints on the 138 kV system. These constraints
and contingencies only affect local areas within the region and risks are not expected
to spread to the 240 kV backbone of the system. The AESO is planning to file a NID for
reinforcement to this 138 kV system by the second quarter of 2012, with development
scheduled to be in place by the end of 2015. In the meantime, the AESO has developed
a procedure to mitigate overload in the area during real-time operation.
9
Category B events result in the loss of any single specified system element under specified fault conditions
and normal clearing.
24-Month Reliability Outlook
PAGE 17
Wabamun Lake/Keg and Edmonton/
Fort Saskatchewan Area Bulk Transmission
The Wabamun Lake area has undergone major transmission upgrades as part of the
interconnection of the Keephills 3 generator and related reconfiguration of Edmonton area
240 kV lines (also referred to as the Edmonton Debottlenecking Project). Construction
of these transmission system upgrades began in the summer of 2010. The transmission
development includes converting the existing line 1202L from 240 kV to 500 kV, adding a
new 240 kV line between the Keephills generating plant and the Edmonton area, upgrading
the capacity of several 240 kV lines and installing phase-shifting transformers at Keephills
320P and in the Fort McMurray area.
After the debottlenecking project is complete, three 240 kV lines will be in place to transport
electricity from the Sundance generating plants to the Edmonton area. Three 500 kV lines
and one new 240 kV high capacity line will connect the Keephills and Genesee generating
plants to the Edmonton area. A phase-shifting transformer has been installed at 240 kV
at the Keephills plant substation in the path of the 240/500 kV existing transformer.
The phase-shifting transformer will help mitigate Category B and C10 overloads and, in
combination with the phase-shifting transformer in the Fort McMurray area, will facilitate
increased transfer capacity to serve Northeast region load.
Operations planning studies were recently completed for the final stage of the Wabamun
Lake area transmission upgrade to determine the operating limits of the Keephills-Genesee,
South of Keephills-Ellerslie-Genesee (SOK) and Northeast11 cutplanes and to ensure the
area operates to the Alberta reliability criteria and standards. For reliable system operation,
operating practices and operator tools will be revised to ensure the total Keephills-EllerslieGenesee (KEG) net-to-grid generation online will not exceed the dynamic stability limit of the
different cutplanes as determined by these studies. A system controller procedure was also
established to provide guidelines on how to operate the phase-shifting transformers at
Keephills and in the Fort McMurray area.
10 11 Category B events result in the loss of any single specified system element under specified fault conditions
and normal clearing.
The Northeast cutplane consists of four 240 kV circuits: 920L (Clover Bar 987s to Lamoureux 71s), 921L (Castle
Downs 557s to Lamoureux 71s), 9L56 (Mitsue 732s to Brintnell 876s) and 9L15 (Brintnell 876s to Wesley Creek 834s.)
They provide transfer paths for energy to and from the Northeast region.
PAGE 18
24-Month Reliability Outlook
The reactive support limitations on legislated Power Purchase Arrangement units in
the KEG area can create operational concerns during peak summer load conditions.
The AESO continues to work with generator owners and operators to address this issue.
This area was constrained several times in 2011 during the construction phase of the
Keephills 3 interconnection and related transmission upgrades project. Congestion may
continue to occur until the second quarter of 2012 as a result of transmission line outages
required to complete the planned transmission upgrades in the Wabamun Lake area
described above.
24-Month Reliability Outlook
PAGE 19
Central Region
The Central region is located between Edmonton and Calgary and includes the Lloydminster,
Hinton/Edson, Drayton Valley, Wainwright, Abraham Lake, Red Deer, Alliance/Battle River,
Provost, Caroline, Didsbury, Hanna and Vegreville areas. This region contains approximately
15 per cent of the provincial peak load and generation capacity totals over 1,800 MW. Area
generation is a mix of hydro, coal-fired, wind, biomass and industrial gas-fired cogeneration.
The transmission system in the Central region has the capacity to serve firm loads in
the region when all elements are in service during normal operation. When the system
is operating with one element out of service (N-1), a number of next contingency scenarios
can result in voltage violations and/or overloads in different parts of the region. Reliable
transmission system operation is maintained through established procedures, operating limits
and AESO–Transmission Facility Owner coordination of maintenance through weekly system
coordination plans. Due to anticipated delays of the transmission reinforcements in the
Wainwright, Battle River, Lloydminster and Provost areas, coupled with load growth in this
region, new RAS and OPPs are proposed to mitigate these constraints in the interim period.
In the first quarter of 2011, the AESO received approval for the Central East Transmission
Development (CETD). This development covers 144 kV systems in the Cold Lake area of the
Northeast Region and some areas of the Central region. This development will resolve the
existing constraints and facilitate the connection of wind projects, cogeneration and
significant load growth of new pipelines.
These transmission upgrades will be developed in two stages. Stage one comprises
the majority of 138/144 kV line rebuilds in the Wainwright, Provost and Cold Lake areas;
a 240 kV double circuit line single-side strung from Bourque (a new substation) to
Bonnyville; and a new 138 kV line from the Wainwright to Edgerton substations. As per the
approved NID, these are required by 2012 but TFO’s schedules indicate these developments
are staged in the 2012 to 2014 time period. The stage two development may be required by
2017 and the AESO will continue monitor the timing, which would be influenced by local area
growth and the need to meet reliability requirements of the transmission system.
PAGE 20
24-Month Reliability Outlook
The Hanna Region Transmission Development project is expected to be completed by the
second quarter of 2013. The completion of this project will provide transmission capacity
to mitigate existing transmission constraints, meet load growth and facilitate connection
of wind projects. It will also improve the performance of the transmission system to meet
requirements of applicable Alberta Reliability Standards and alleviate current requirements
in effect on the South of Anderson (SOA) cutplane. In the meantime, the AESO has
developed operating procedures aligned with ISO rule 9.4 that will be used in real-time
operation to manage the SOA cutplane limits.
The AESO filed a NID for transmission development for the Red Deer and Didsbury areas
in July 2011 and is awaiting AUC approval. The transmission reinforcements described in
the NID will mitigate existing system constraints including thermal overloads on the 138 kV
system parallel to SOK 240 kV path and meet load growth in the study areas. The target
completion of the Red Deer region transmission development is the first quarter of 2014.
24-Month Reliability Outlook
PAGE 21
South Region
The South region of Alberta has the Canada-U.S. border to the south and is bordered on the
north by the Abraham Lake, Caroline, Didsbury and Hanna areas and on the west and east
by B.C. and Saskatchewan respectively. The region makes up approximately 30 per cent of
the province’s peak load (mainly residential and commercial) and has 3,000 MW of Alberta’s
total installed generation capacity. The generation is a mix of hydroelectricity, gas-fired and
coal-fired generation and approximately 780 MW of wind facilities.
Transmission capacity in the southeast area of the region has been enhanced significantly
since the Amoco Empress area transmission addition was completed in 2009 and 2010. This
transmission development restored the Alberta-Saskatchewan intertie limits to the original
design level of 150 MW in both directions under normal conditions. The upgrade has also
improved system performance on 240 kV line contingencies. Constraints may occur due
to limitations within the Saskatchewan system or during planned or forced outages to
transmission facilities within the Alberta system.
The AESO and Transmission Facility Owner AltaLink are developing project schedules and
specifications for the Southern Alberta Transmission Reinforcement (SATR) phases one
and two, with project components expected to be in service beginning September 2011
with completion by December 2016.
The Russell phase-shifting transformer, Milo Junction switching station 356S, Cassils
substation 324S and Bowmanton substation 244S, and the double circuit 240kV line from
Elkwater to Bowmanton are planned to be in service by the fourth quarter of 2013 which
will facilitate wind integration in the south.
Transmission constraints in the 138 kV system in the southeast area will continue until
the Medicine Hat 138kV transmission upgrades within the SATR project are completed.
This will move significant load from the existing system to the new 240 kV system at
Bowmanton substation.
Even after commissioning the southwest 240 kV development in the first quarter of 2011,
which included double circuit 240 kV lines from the new Goose Lake 103s to Peigan 59s
to North Lethbridge 370s, some wind generation curtailments will continue to occur under
normal system operations until phase one of the SATR is completed. Once this is done,
transmission capacity to support existing and new wind generation in the southwest and
southeast will be enhanced.
PAGE 22
24-Month Reliability Outlook
The overload remedial action schemes (RAS) on the southwest system will continue and
new RAS may be required as new wind generation comes online before the completion of
SATR phases one and two. These RAS have been installed to ensure the area transmission
system meets the performance requirements of Category A, B and C contingencies.
The current 138 kV and 240 kV systems serving south Calgary and the High River planning
areas, and between Calgary and the south of the province, are approaching capacity and
will require substantial reinforcement to accommodate load growth, new gas generation
connection requests and south-to-north transfers related to new wind generation. The
AESO has completed a system study that proposes the Foothills Area Transmission
Development (FATD) plan. This plan will improve transfer capacity between Calgary
and southern Alberta, meet area load growth and facilitate the connection of new
generation, such as the ENMAX Shepard Energy Centre and other plants that have received
regulatory approval in the High River area. The AESO is planning to file components of the
FATD plan in separate filings with the AUC. The first application was filed in the second
quarter of 2011.
The transmission system in the city of Calgary is reaching its limit due to increased
load growth and it is becoming increasingly difficult to arrange maintenance on many
transmission facilities. When specific transmission equipment is removed from service for
maintenance, the next single contingency can result in uncontrolled loss of load in the area.
FATD completion will address these constraints in south Calgary. To address 138 kV system
constraints in the north Calgary and Airdrie areas, the AESO is performing planning studies
to develop a plan for the North Calgary Area Transmission (NCAT). The AESO is planning to
file the NCAT project NID with the AUC in 2013.
The development recommended in a NID approved by the AUC in July 2009 to replace four
existing transmission cables and terminal equipment serving the Calgary central business
district is complete. Two of the new cables were energized in the fourth quarter of 2010 and
the remaining two cables were energized in the fourth quarter of 2011.
24-Month Reliability Outlook
PAGE 23
North-South Transmission
The Edmonton to Calgary bulk transmission system is comprised of six 240 kV lines
between the Wabamun Lake/Edmonton area and Calgary. These six circuits are collectively
referred to as the South of Keephills-Ellerslie-Genesee (SOK) cutplane. These lines transfer
baseload coal generation and Brazeau hydro generation to the southern part of the province
to meet the major load requirements of the Calgary region. In addition, these lines provide
access to the Alberta-B.C. intertie.
The power flow across the SOK cutplane and minimum voltage levels at several key buses
on the north-south path are used to define the transfer capability of the north-to-south flow.
Under normal system conditions, with all elements in service, the SOK 240 kV system has
the capacity to accommodate forecast flows in 2012. However; based on the AESO’s
transmission planning criteria, the existing SOK transfer capability is not adequate under
anticipated planning flows and reinforcement of the SOK cutplane is required as soon
as is practicable. The Government of Alberta approved the need for two 500 kV HVDC
transmission lines between Edmonton and Calgary on February 23, 2012 and the AESO
anticipates the lines will be in service in the 2015 to 2016 period.
Before the completion of transmission development between Edmonton and Calgary, the
projected flows on the SOK 240 kV system will continue to pose a concern, especially during
certain transmission and generation outages, to the operation and reliability of the AIES.
The AESO will continue to monitor the situation and develop mitigation plans to address
these concerns until such time as approved transmission developments are in service.
PAGE 24
24-Month Reliability Outlook
Alberta Intertie Capability
As new interties are being contemplated from multiple jurisdictions, the AESO is currently
consulting with stakeholders to review the intertie framework to ensure it supports fair,
efficient, and openly competitive transactions while advancing government policy. With the
Montana-Alberta intertie (MATL) under construction, the immediate focus is to review and
develop market rules to manage the operational and market integration of multiple interties,
including the fair allocation of transmission capability.
One 500 kV circuit and two 138 kV circuits between Alberta and B.C. comprise three circuits
the Western Electricity Coordinating Council (WECC) defines as Path 1. The current path
rating of the B.C. intertie is 1,000 MW in export12 mode and 1,200 MW in import13 mode.
However, the actual operating limit is much lower due to the need to maintain acceptable
levels of frequency in Alberta in the event of intertie separation while importing, and voltage
concerns in the Calgary area in the event of 240 kV line trips in the Calgary area while
exporting. The current available transfer capability (ATC) between Alberta and B.C. is
735 MW for exports and 600 MW for imports. The import limit is expected to increase to
700 MW in early 2012 with the full implementation of the Load Shed Service-imports (LSSi)
product described in the demand response section.
The McNeill back-to-back alternating current AC-to-DC converter station that connects
Alberta and Saskatchewan is referred to as WECC Path 2. Since the completion of transmission
system developments in the Amoco Empress area in 2009 to 2010, a maximum import and
export Total Transfer Capability (TTC) of 150 MW is available. Constraints on either the
Alberta or Saskatchewan system may lower the TTC during real-time operation.
The Montana Alberta Tie Line (MATL), a 230 kV merchant intertie between Montana and
Alberta, is expected to be in service during 2012. This intertie will provide an alternate
source of energy exchange between Alberta and the Northwest U.S.; however, the MATL
is not expected to increase the net import and export limits between Alberta and the
remaining WECC system.
12
13
Alberta to B.C.
B.C. to Alberta
24-Month Reliability Outlook
PAGE 25
Wind Integration
Wind power facilities in the province have relatively high capacity factors14 with some
reaching as high as 35 per cent on an annual basis, making Alberta an attractive place for
wind development. Wind power in Alberta has seen substantial growth in the last few years.
As of December 2011, 865 MW of generating capacity from 15 wind farms, 6.4 per cent of
total installed generation capacity, was connected to the transmission system. Wind power
provided 3.16 per cent of the total energy consumed in Alberta (AIL) during 2011. There
continues to be strong interest in building wind generation. There are over 5000 MW of wind
generation projects in the connection queue, with a large portion of that total amount slated
to be connected to the grid over the next 24 months.
The AESO is currently pursuing several initiatives to further refine and define rules,
standards, information technologies and tools needed to integrate as much wind power into
the Alberta system as feasible without compromising system reliability or the fair, efficient
and openly competitive operation of the market. In September 2010, the AESO published
the Short Term Wind Integration Recommendation Paper describing the tools and practices
needed to integrate up to 1,100 MW of wind into the system. Wind power management
and site-specific wind power forecasts were the main recommendations for the short-term
recommendation that will be fully operationalized by the end of the first quarter of 2012.
The AESO also released a discussion paper in December 2010 outlining possible products
and market rules that will take longer to implement but are intended to support the
increasing amount of wind capacity expected in Alberta for 2012 and beyond. Extensive
consultation with industry in 2011 culminated with a recommendation from an industry
working group in December 2011. The Phase Two Recommendation Paper with the
AESO’s proposed implementation plan should be released for consultation in the first half
of 2012. Wind power forecasting is also being integrated into a variety of market systems
and the AESO is working with wind facility owners to improve and efficiently utilize the
wind power forecast.
Alberta continues to be a leader in wind integration. The province provides an attractive
environment for future wind power development because of our market structure, significant
wind regimes and the AESO’s forward-looking initiatives developed in consultation with
industry stakeholders, as well as our sharing of best practices in wind integration with
Independent System Operators across North America.
14
The net capacity factor of a power plant is the ratio of the actual output of a power plant over a period of time
and its output if it had operated at full nameplate capacity the entire time.
PAGE 26
24-Month Reliability Outlook
Demand Response
Demand side participation is a key component of a fair, efficient and openly competitive
market. As part of efforts to increase demand response opportunities, the AESO commissioned
a study by the Brattle Group to examine opportunities to enhance demand response in the
Alberta market.15
The first direct way for load customers to participate in the energy market is through responding
to the electricity price in the real-time spot market. Approximately 175 to 300 MW of load
participates in the market by voluntarily reducing demand when pool prices exceed their
self-defined price threshold.
Load also has the opportunity to participate in the supplemental reserve market by reducing
demand when directed by the AESO following a significant loss of generation in Alberta.
Load market participants provided approximately eight per cent of Supplemental Reserve in
2010 and 10 per cent in 2011. In order to increase the range of customers that can potentially
supply Supplemental Reserve, the AESO recently posted changes to the Supplemental
Reserve technical standard that allows small loads to be aggregated in order to collectively
sell the service.
In addition, the transmission tariff creates several opportunities for demand customers. The
AESO offers a demand opportunity service rate (DOS) for transmission customers who are
able to reduce demand when transmission capacity is restricted. The AESO also recently
added a peak load forecast report to help customers manage their consumption during
system peak load hours.16
In August 2011, the AESO completed a Request for Proposal (RFP) process to procure a
Load Shed Service-imports (LSSi) to support the import capability of the Alberta transmission
system and increase the transfer capability of the B.C. intertie. A total of 432 MW of load
were selected to supply the service under the RFP, and the providers will be offering the
service by the end of the first quarter of 2012. As a result of the LSSi service, the maximum
import available transfer capability on the B.C. intertie will increase to 700 MW from the
current level of approximately 600 MW.
15
16
http://www.aeso.ca/downloads/Brattle_RTO_DR_Review_Final.pdf
See http://ets.aeso.ca/ and select “Peak Load Forecast” from the Report drop down menu.
24-Month Reliability Outlook
PAGE 27
Highlights of the 24-Month
Reliability Outlook
The Alberta Interconnected Electric System (AIES) will continue to provide an adequate level
of reliability using the AESO’s operating practices and procedures. However, the level of
congestion on the system is expected to increase in some regions due to load growth
and new connections until more transmission is built.
The AESO’s priority is timely approval and implementation of proposed transmission
upgrades to meet future reliability needs.
Supply reserve margins will be adequate during the next two years. Close coordination
of generator and transmission outages is required to ensure adequate supply and to avoid
constraint events during real-time operation.
Over the next 24 months, emphasis will remain on implementing operating procedures,
system analysis and the availability of training and tools to equip system controllers to
manage the reliability of the Alberta system. In the longer term, the AESO’s Long-term
Transmission Plan identifies transmission projects that will enhance the transmission
system to eliminate constraints and continue to enable a fair, efficient, and openly
competitive wholesale electricity market.
PAGE 28
24-Month Reliability Outlook
In Summary
Information in the 24-Month Reliability Outlook 2011–2013 is provided from the perspective
of assessing the AESO’s ability to reliably operate the AIES over the 2011 to 2012 winter
season and the next two years. Supporting information and forecasts referred to throughout
this document are available at www.aeso.ca
This document complements the AESO’s existing publications and supports our
commitment to sharing information with market participants, other stakeholders and
all Albertans in a timely, open and transparent manner. Readers are invited to provide
comments or suggestions for future reports.
For more information or to give us your feedback, contact [email protected]
24-Month Reliability Outlook
PAGE 29
Alberta Electric System Operator
2500, 300-5th Avenue SW
Calgary, Alberta T2P 0L4
Phone: 403-539-2450
Fax: 403-539-2949
www.aeso.ca
www.poweringalberta.com
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