AESO Long-term Transmission Plan
FILED JUNE 2012
Table of Contents
ExEcutivE Summary 1
1.0 introduction 13
2.0 Background 15
2.1 role of the aESo 15
2.2 value of transmission 20
2.3 Planning for uncertainty 25
2.4 transmission planning scenarios and sensitivities 27
3.0 aESo Planning ProcESS 29
3.1 Stakeholder consultation process 30
3.2 determining need 33
3.3 load forecast process 35
3.4 generation forecast process 39
3.5 System planning and reliability standards 42
3.6 additional key considerations 47
3.6.1 Interties 47
3.6.2 Transmission technologies 49
3.6.3 Environmental considerations 51
3.6.4 AESO system operations 51
3.6.5 Ancillary services 52
3.6.6 Market evolution 55
3.6.7 Transmission Constraints Management (TCM) 56
3.6.7.1 Impact of transmission constraints on the wholesale electricity market 58
3.6.8 Telecommunications 59
Table of Contents
AESO Long-term Transmission Plan
4.0 aESo analySiS and Planning rESultS 61
4.1 overview 61
4.2 load forecast – Future demand and Energy outlook (2009-2029) 61
4.2.1 Overview 61
4.2.2 Summary of key inputs 62
4.2.3 Anticipated trends 66
4.2.4 Uncertainties and concerns looking forward 67
4.3 generation forecast 69
4.3.1 Gas-fired generation 71
4.3.2 Coal 72
4.3.3 Wind 72
4.3.4 Other renewable projects and new technologies 73
4.3.5 Large projects 73
4.3.6 Baseline generation scenarios 73
4.4 Bulk transmission system including cti 76
4.4.1 Overview 76
4.4.2 Transmission technology alternatives 78
4.4.3 Project status 79
4.4.3.1 Edmonton to Calgary transmission system reinforcement 79
4.4.3.2 Heartland transmission system reinforcement 82
4.4.3.3 Fort McMurray transmission system reinforcements 85
4.4.3.4 Southern Alberta Transmission Reinforcement (SATR) 86
4.4.3.5 Foothills Area Transmission Development (FATD) 89
4.4.3.6 South Calgary transmission system reinforcements 91
4.4.3.7 Northwest transmission system reinforcements 93
4.4.4 Bulk projects cost estimates and timelines 95
4.4.5 Unique considerations and uncertainties on the bulk system 96
4.4.6 Bulk transmission system post-2020 99
Table of Contents
AESO Long-term Transmission Plan
4.5 regional transmission system projects 102
4.5.1 Northwest region 102
4.5.1.1 Overview 102
4.5.1.2 Status of projects 105
4.5.1.3 Unique challenges, uncertainties and concerns 107
4.5.2 Northeast region 108
4.5.2.1 Overview 108
4.5.2.2 Status of projects 110
4.5.2.3 Northeast region transmission projects 112
4.5.2.4 Unique challenges, uncertainties and concerns 113
4.5.3 Edmonton region 114
4.5.3.1 Overview 114
4.5.3.2 Status of projects 117
4.5.3.3 Edmonton region transmission projects 118
4.5.3.4 Unique challenges, uncertainties and concerns 119
4.5.4 Central region 120
4.5.4.1 Overview 120
4.5.4.2 Status of projects 122
4.5.4.3 Central region transmission projects 123
4.5.4.4 Unique challenges, uncertainties and concerns 123
4.5.5 South region 124
4.5.5.1 Overview 124
4.5.5.2 Status of projects 126
4.5.5.3 South region transmission projects 127
4.5.5.4 Unique challenges, uncertainties and concerns 127
4.6 long-term transmission Plan costs 128
4.6.1 Project cost estimates 129
4.6.2 Transmission rate impact 132
4.6.3 Reconciliation of costs 135
5.0 concluSion 139
Table of Contents
AESO Long-term Transmission Plan
aPPEndicES 141
Appendix A Glossary of Terms 141
Appendix B 24-Month Reliability Outlook (2010 – 2012) 151
Appendix C 2010 Annual Market Statistics 179
Appendix D Part 1 – FC2009 Overlay 207
Appendix D Part 2 – Future Demand and Energy Outlook (2009 – 2029) 219
Appendix E Generation Outlook 2009 – 2029 283
Appendix F Interties 323
Appendix G Advancements in Transmission Technology 337
Appendix H Ancillary Services Participant Manual 349
Appendix I Alberta’s Wholesale Electricity Market Design 401
Appendix J 2011 Long-term Telecommunications Plan 415
Appendix K Part 1 – The Value of Transmission 439
Appendix K Part 2 – Impact of Transmission Constraints on the Wholesale Electricity Market 453
Table of Contents
PagE 1
Executive Summary
The Long-term Transmission Plan (filed June 2012) – also referred to as the LTP or the
Plan – is the Alberta Electric System Operator’s (AESO) vision of how Alberta’s electric
transmission grid needs to be developed to support continued provincial economic growth.
Transmission is a key enabler of Alberta’s $300 billion economy. The safe and reliable delivery
of electricity is essential to ensuring Alberta’s long-term growth and continued standard of
living. Alberta has had minimal major transmission system upgrades since the early 1980s.
This LTP builds on the AESO’s 2009 Long-term Transmission System Plan (2009 LTP)
and incorporates the most recent information available. This LTP sets out a blueprint that
identifies constraints or limitations, and recommends when and where the transmission
system needs to be expanded or reinforced to ensure the Alberta Interconnected Electric
System (AIES) continues to meet the province’s current and future electricity needs.
In developing this LTP, the AESO is guided by the Province of Alberta Electric Utilities Act
(EUA), the Transmission Regulation (T-Reg), and public policy such as the direction articulated
in the Government of Alberta’s 2008 Provincial Energy Strategy. The AESO’s LTP projects
system conditions for at least the next 20 years. Transmission investment is needed to
reliably and efficiently serve expanding demand, reduce transmission congestion and related
congestion costs and facilitate a competitive market. The AESO plans for a system that
is free of congestion1, meets Alberta reliability standards, and is in the public interest.
Executive Summary
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1 See s. 10(1)(a) of the T-Reg for a full listing of requirements for the LTP.
PagE 2
AESO Long-term Transmission Plan
Executive Summary
The AESO is required to make arrangements for the construction of transmission facilities
in advance of forecast need due to long project development timelines.
Building in advance of need and planning for an unconstrained grid provides certainty to
investors in new generation projects that they will have the ability to deliver electricity to
Alberta households and businesses. Further, it gives those in other industries the confidence
to do business in the province, knowing that power will be there when they need it. Alberta’s
future prosperity depends upon a reliable transmission system, and a competitive electricity
market. This LTP was developed by experts whose role is to plan the transmission in the
interest of Albertans.
This LTP utilizes inputs from various sources including stakeholders, market participants,
public information sessions, third party experts and internal expertise. AESO system planning
does not stop with the publication of a particular version of the Plan.
Continuous planning and testing is essential to ensure the development of a robust, flexible
and efficient transmission system. A comprehensive planning regime involves a rigorous
analysis of a variety of public policy, economic and transmission scenarios, as well as related
sensitivities. Economic scenarios provide forecasts of future demand for electricity and the
anticipated generation development to meet that demand. Transmission scenarios ultimately
establish the need for transmission projects, projected in-service dates (ISDs) and staging
of projects when appropriate.
The AESO is continually assessing inputs and circumstances to test the effect they may
have on the LTP, its project components and Alberta’s transmission system.
Since filing the 2009 LTP, the AESO has updated load and generation forecasts, customer
connection requests and the Alberta economic growth outlook. The AESO also revalidated
the need for the four Critical Transmission Infrastructure (CTI) projects identified in the
2009 LTP and reconfirmed the need for substantial transmission upgrades. This LTP identifies
specific projects and related cost estimates, technology to be employed and in-service
dates, and considers the opportunity for staging projects where practical
and prudent.
This LTP recognizes the Alberta economy has emerged from the recent global recession,
reinforcing the long-term growth prospects for the province. Economic fundamentals are
strong for Alberta and long-term Gross Domestic Product (GDP) growth is forecast to be
in the range of 3.0 to 3.2 per cent annually for the next 20 years. The key driver of the
economy continues to be investment in oilsands, as evidenced by third party forecasts
and confirmed by customer connection requests in the Northeast region of the province.
Successful oilsands development relies on the availability of significant electrical
infrastructure.
The AESO’s objective is to continue to evolve the LTP content to include information
on additional, integral non-wires elements thereby increasing the comprehensive nature
of the LTP for future filings with the Alberta Utilities Commission (AUC).
PagE 3
AESO Long-term Transmission Plan
Executive Summary
Key highlights from the loNg-term trANsmissioN PlAN (fileD JUNe 2012)
n The Plan analysis reconfirmed the need for the four CTI projects and major regional
transmission projects identified in the 2009 LTP. This LTP has incorporated
modifications, in part in response to stakeholder consultation, to mitigate costs and
meet adjusted growth profiles. LTP projects have been reviewed and reflect updated
cost estimates as filed by transmission facility owners (TFOs) with the AUC as well
as changes to ISDs where appropriate. Changes to ISDs are consistent with the
updated forecasts of demand growth.
n No new CTI projects are being proposed.
n This LTP has identified several smaller regional projects required to facilitate timely
execution of connection requests from both load and generation customers,
as well as meet Alberta Reliability Standards which became effective in 2010.
Consistent with the regulatory process, each regional project will undergo the
two-stage regulatory review by the AUC, including both the needs identification
and facility applications.
n Several projects to replace outdated equipment and facilities and add new
transmission lines have been approved by the AUC and are now completed
or near completion. This LTP is based on the assumption that these projects
will be in operation as planned.
n Based on recent industry announcements, some of the projects previously identified
for the renewable and low-emission energy zones in the northeast and northwest
regions of the province have been cancelled and/or deferred beyond 2020.
n The estimated project costs in this LTP are slightly below the cost estimates
previously identified in the 2009 LTP. Figure 1 shows the reconciled cost differences
from the 2009 LTP. This Plan’s updated aggregate cost estimate for the projects
anticipated to be in service by 2020 is $13.5 billion (2011 dollars).
n This LTP identifies 53 projects in all. Two thirds of the projects support investment in
regional development at an estimated cost of $8.3 billion. One third of the total cost
of the projects represent the four CTI projects at an estimated cost of $5.2 billion.
n 60 per cent of the costs are for projects in development stages, with $3 billion
at the Needs Identification (NID) stage and approximately $5.2 billion at the
Facilities Application (FA) stage.
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AESO Long-term Transmission Plan
Executive Summary
n The remaining 40 per cent of the costs are for projects in the planning stage,
representing approximately $5.3 billion.
n Figure 2 illustrates that the total cost of this Plan once incurred would increase
the electric bill for an average residential consumer (using 600 kilowatt hours (kWh)
per month) by $11 per month over the next 10 years, from about $92 per month
in 2011 to about $103 per month in 2020 2.
n Figure 2 also illustrates that the total cost of this Plan once incurred would increase
the average delivered electricity costs for an industrial consumer by $19/MWh over
the next 10 years, from about $79/MWh in 2011 to about $98/MWh in 2020 2.
n The transmission portion of the total delivered energy cost to consumers is
approximately 10 to 20 per cent for residential customers and 20 to 40 per cent for
end use industrial customers. Residential consumers pay energy, retail, distribution
and transmission cots. Industrial consumers pay energy and transmission costs.
As a result, the transmission portion of the total delivered cost of energy is
proportionately higher for industrial than for residential customers.
2 These estimates hold other costs constant, and do not include increases due to escalation of those other costs.
$16,000
$14,000
$12,000
$10,000
$8,000
$6,000
$4,000
$2,000
$0
$ m
illio
ns
1,122
14,463
1,927
1,520
1,281 1,216
10,951
1,473
13,545
2009 LTP(2008 $)
Projects cancelled(2008 $)
Projectsdelayed
beyond 2020(2008 $)
Projectscompleted
or nearcompletion
(2008 $)
Escalation2008 to 2011
(2011 $)
Adjusted2009 LTP(2011 $)
New projectsand scopechanges(2011 $)
This LTP(2011 $)
New
Scope change
Figure 1: Reconciliation of this LTP and 2009 LTP costs
PagE 5
AESO Long-term Transmission Plan
Executive Summary
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
$120
$100
$80
$60
$40
$20
$0
Ave
rage
res
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/mon
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Energy, distribution and retail Transmission
$9/month $21/month
Ave
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ind
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/MW
h)
Energy Transmission
$16/MWh
$35/MWhTransmission
Energy
Figure 2: Transmission cost impact on residential and industrial customers
Residential
Transmission
Energy, distribution and retail
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
$120
$100
$80
$60
$40
$20
$0
Industrial
PagE 6
AESO Long-term Transmission Plan
AssUmPtioNs AND iNPUts
The AESO continually works with customers and stakeholders to monitor changes to
the key inputs to our forecast of both load and generation. This LTP embodies the practice
of continuous improvement at the AESO. To be prudent, the Plan is designed to be
comprehensive and flexible in order to reflect the complexities and dependencies of project
development, and to accommodate the variability of industries and business cycles. It
addresses intra-Alberta physical transmission construction and reliability standards, and
defines the need for restoring Alberta’s intertie capacity, temporary non-wires solutions,
ancillary service requirements, system operations protocols, telecommunications
requirements and criteria for market sustainability.
With each update, the Long-term Transmission Plan considers a variety of scenarios to
help forecast future demand for electricity and the anticipated generation development to
meet that demand. It also identifies a number of transmission scenarios which ultimately
establish the need for transmission projects, projected in-service dates and estimated
costs. Transmission investment is needed to reliably and efficiently serve expanding
demand, reduce transmission congestion (and related congestion costs) and facilitate
a competitive market.
The AESO has updated load and generation forecasts using third party experts such
as The Conference Board of Canada, the Canadian Association of Petroleum Producers,
and IHS Global Insights, as well as updated customer connection requests. Of note, the
AESO is currently managing over 200 connection requests for load and generation facilities.
The forecasts are consistent with the Alberta economic outlook.
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PagE 7
AESO Long-term Transmission Plan
Executive Summary
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
Ave
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W)
Actuals Current forecast
Figure 3: Historical actual and current load forecasts
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
As part of our consultative efforts, in 2010 the AESO contracted The Brattle Group, an
independent international consulting firm, to conduct a study to assess if the provincial
wholesale electricity market design is sustainable and could be expected to attract the
necessary investment in electricity generation. The study found no compelling need to
change our current market design. While this is a positive endorsement, the AESO notes
that generation and load are added to our market based on the assumption that the
AESO plans for an unconstrained transmission system that allows for infrastructure
investment today and in the future as required by the T-Reg.
Further studies and stakeholder consultation input on this LTP have validated the previously
defined inputs to the AESO’s annual Future Demand and Energy Outlook 2009-2029
(FC2009). This report found that despite short-term delays in economic growth during the
2008/2009 recession, as shown in Figure 3, continued economic growth in the province
is expected. The AESO’s transmission planning processes are purposefully staged and
flexible to accommodate changes in forecast demand.
PagE 8
AESO Long-term Transmission Plan
Executive Summary
44% Coal 5,782 MW
41% Gas 5,371 MW
7% Hydro 879 MW
6% Wind 777 MW
2% Other 203 MW
Current installed capacity
29% Coal 5,588 MW
50% Gas 9,634 MW
5% Hydro 981 MW
13% Wind 2,500 MW
2% Other 395 MW
Figure 4: Generation mix: current and 2020 baseline
2020
Strong energy growth is expected from 2011 to 2015, driven by oilsands development
and corresponding economic and population growth. Current third party estimates show
that by 2020 over $180 billion will be invested in oilsands projects. Demand for power
has increased 32 per cent over the last 10 years with demand growth forecast to average
3.2 per cent per year over the next 20 years. 2010 demand growth statistics show an
under forecast of peak demand for the year, while average growth came in slightly
below expectations.
A number of key changes since the 2009 LTP have shaped the AESO’s most recent
assessment of future generation in Alberta and are represented in this LTP generation
scenarios. Development of generation in Alberta will be driven by growth in customer
demand, commercial business decisions and the need for capacity to replace retired or
retiring generation units. The fuel choice for generation will also be affected by any changes
in public policy.
New generation construction decisions will be determined by private sector investment
which is influenced by a variety of factors. As shown in Figure 4, the AESO expects the
future generation mix to become more heavily weighted toward natural gas in the near
future, while wind generation also becomes more predominant on our system. Alberta
will need to add approximately 13,000 megawatts (MW) of new effective generation over
the next 20 years – nearly equal to the current amount of electricity that can be produced in
the province today – to meet forecast increases and replace aging and retiring power plant
facilities. The AESO notes that generation developers take on 100 per cent of the risks
and costs associated with building power generation in Alberta, while consumers pay for
the cost of the transmission infrastructure, as well as the energy they directly consume.
PagE 9
AESO Long-term Transmission Plan
Executive Summary
The most significant factors impacting the future generation mix include:
n Evolving climate change policy which has led to a reduced forecast greenhouse
gas (GHG) cost of approximately $30/tonne in 2020, down from previous estimates
of $60/tonne due to continual delays in North American carbon pricing mechanisms.
The estimated costs of GHGs in Canada are assumed to be in line with U.S.
cost estimates.
n The federal government announced that coal-fired generation facility emission
standards will be fixed at emission levels of natural gas generation facilities as of
2015. This would likely result in coal-fired generation retirements occuring at the later
of 45 years (facility end of life) or expiration of Power Purchase Arrangements (PPAs).
n Current healthy natural gas supplies combined with expected stable long-term gas
prices over the next ten years will incent further development of natural gas-fueled
power generation.
n The expiration of the federal subsidy program for renewable power generation and
its impact on future wind generation opportunities, and uncertainty with respect to
whether or not there will be new programs in the future.
n High likelihood of new incremental cogeneration facilities in the Northeast region
of Alberta.
n Recent industry announcements associated with new facility connection requests
and the possible early retirement of existing generation facilities.
The AESO has addressed these variables using scenario analyses, which can be found in the
Generation Outlook (2009 – 2029) Appendix E. The scenarios that were considered include:
n Baseline – represents the AESO’s view of the most likely outcome for both load
growth and generation development.
n greenest – represents higher amounts of renewable energy on our system
due to higher carbon prices than what are included in our baseline assumptions.
n High cogeneration – has a higher amount of cogeneration built in the northeastern
part of the province as compared to baseline.
This LTP represents the AESO’s best judgment at this time, recognizing that our industry
is dynamic and that planning flexibility is key. The AESO will continue to monitor these
assumptions and provide updates as required.
PagE 10
AESO Long-term Transmission Plan
Executive Summary
fUtUre moNitoriNg of the loNg-term PlAN
Planning and forecasting involve uncertainties that need to be acknowledged and accounted
for over the 20 year span of this LTP. Crude oil and natural gas prices continue to be
a major contributor to Alberta’s prosperity. Price uncertainty influences overall economic
development as well as the development of specific projects, especially those in northern
Alberta. Sustained higher oil prices since the recession are expected to continue to cause
many customer connection projects to be accelerated, resulting in the advancement of
several regional transmission projects identified in this LTP. Accelerated project schedules
will likely have an impact on project costs.
Sustained oil prices would also increase demand for skilled labour throughout North America,
certainly in Alberta, and may result in labour shortages. This may have cost and schedule
implications for engineering, procurement and construction of transmission projects as
they often compete with the oil industry. Commodity price fluctuations will have an impact
on project cost estimates as nearly 30 per cent of the total cost of a typical transmission
project is attributable to the cost of equipment and materials that are directly influenced
by commodity prices such as steel and aluminum.
Increasing natural gas prices due to increased demand for gas both here in Alberta and in
North America would impact the generation outlook. The anticipated legislated retirement
of coal fired generation facilities would facilitate increased demand for natural gas, as
opposed to other potential sources such as large scale hydro and nuclear that have much
higher capital costs, financing challenges, increased regulatory hurdles and inflexible geographic
challenges. The project schedules may be impacted if retirement of coal plants or in-service
dates of new gas plants are adjusted due to high gas prices. The AESO’s LTP is flexible
enough to accommodate such changes and we will continue to monitor the fundamental
outlook for resources and fuel choices for new generation in the interests of Albertans.
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AESO Long-term Transmission Plan
NorthwesternArea
Fort McMurrayArea
CalgaryArea
SouthernArea
Thermal generator
Hydro plant
HVDC converter
Existing 240 kV
Existing 500 kV
Proposed 240 kV AC
Proposed 500 kV AC
Proposed HVDC
Existing substations
Hubs
HeartlandArea
3 3
2
11
Wabamun Lake/Edmonton Area
Note: For illustrative purposes only; does not depict actual line routes or substation locations.
HVDC: high voltage direct currentkV: kilovoltAC: alternating current
Critical Transmission Infrastructure Projects (CTI)
Edmonton-Calgary
Heartland
1
2
Fort McMurray 500 kV
South Calgary substation
3
4
4
Figure 5: Bulk system projects
Executive Summary
PagE 12
AESO Long-term Transmission Plan
Executive Summary
CoNClUsioN
This LTP presents an integrated, comprehensive and strategic upgrade of the transmission
system that meets statutory requirements, aligns with public policy and strategy respecting
electricity, meets load growth, and facilitates development of Alberta’s abundant natural
resources for the next 20 years. This Plan is robust and flexible, and will be updated again
in two years to report on changes in business and economic conditions and incorporate
any required amendments in the next LTP. This Plan provides efficient, reliable, cost effective
solutions to Alberta’s electric transmission system and facilitates non-discriminatory system
access service to customers by timely implementation of transmission system enhancements.
The T-Reg directs the AESO to be proactive in its planning and development of the
transmission system since market signals alone do not provide timely indicators for
transmission development given the long lead time associated with these projects. While
this LTP is robust and flexible, there are implementation challenges. These challenges range
from environmental considerations and regulatory delays to cost and availability of labour
and materials. The AESO will respond to these challenges by establishing milestones where
appropriate, incorporating project staging, continued stakeholder consultation, facilitating
efficient regulatory coordination and filing and developing competitive procurement of
equipment and services. This allows consumers to receive maximum value from transmission
investments by timing the construction phases of projects to align with investment and
scheduled need dates.
This Plan introduces a supplement that will be updated every six months to track and
publish project updates, plus any material changes to the forecast, including refined project
cost estimates. The AESO’s objective is to continue to evolve the LTP content to include
information on additional and integral non-wires elements thereby increasing the value
to stakeholders and the comprehensive and transparent nature of the LTP.
The AESO will continue to monitor key economic indicators, changes to legislation or
the regulatory framework, respond to customer requests for both load and generation
connections and evaluate the requirements for upgrading the transmission system.
Stakeholder engagement will remain an essential component in preparing the next
iteration of the LTP. Engagement with the public and with industry will continue, furthering
the objectives related to establishing CTI milestones, initiating a competitive process for
future transmission projects and determining intertie strategies.
This LTP process will serve to provide Albertans with continuing access to safe, reliable
and affordable electric power. Alberta’s future prosperity will be facilitated by having a reliable
transmission system, adequate generation resources, timely investment in infrastructure and
a competitive electricity market to benefit all Albertans.
PagE 13
1.0Introduction
The Alberta Electric System Operator (AESO) has a legislated mandate to ensure the
interconnected transmission system is operated in a safe, reliable and economic manner
and to plan the capability of the transmission system to meet the demand for electricity
now and in the future. The Electric Utilities Act (EUA) requires the AESO to assess the current
and future needs of market participants and to plan for the construction of transmission
in advance of need. The Transmission Regulation provides additional clarity about this
responsibility and requires the AESO to make assumptions about future load growth,
anticipate generation changes, assess market conditions, determine requirements for
ancillary services, plan for telecommunications networks and integrate these assumptions
into a transmission plan.
The Long-term Transmission Plan (filed June 2012) – also referred to as the LTP or the Plan –
is a fundamental part of the AESO’s planning process. The LTP identifies what transmission
infrastructure needs to be built over the next 20 years so that the Alberta Interconnected
Electric System continues to meet the province’s current and future electricity needs. The
LTP sets out a blueprint that identifies constraints or limitations and recommends when and
where the transmission system needs to be expanded or reinforced, both at the bulk-system
and regional delivery levels.
A large part of the AESO’s role is planning effective and prudent transmission system expansions
to serve new generation development and demand growth in a competitive electricity market.
The knowledge and information gathered in the planning stages is also critical to ensuring the
province’s transmission system is upgraded when and where it is needed.
1.0 Introduction
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PagE 14
AESO Long-term Transmission Plan
The AESO uses this information to identify the best solutions to strengthen the electricity
grid. The LTP is flexible and is based on information available today regarding assumptions
of future conditions and circumstances. The AESO periodically reviews inputs to the LTP
to determine if circumstances warrant a significant change in the approach. Should new
information become available, the LTP is updated accordingly. An updated version is required
to be filed with the Alberta Utilities Commission (AUC) and the Minister of Energy at least
every two years, copies of which are available to the public.
This LTP takes a comprehensive and cost-effective approach to planning a strong transmission
system so all Albertans can continue to depend on safe and reliable electricity. At the same
time, this approach provides confidence for all power generators, including those who want
to build more renewable and low-emission power generating facilities. It also provides
confidence to investors in industry and business that the reliable, competitive electricity
they depend on will be available to support their future plans.
To anticipate what is needed, the AESO considers a range of factors including Alberta’s
economic outlook. The AESO planning team, including engineers, economists and
transmission system planners, analyzes electricity consumption patterns in every area of
the province and integrates data from many sources to determine where electricity demand
will grow, where generation is or may be planned to meet that demand, and what additional
transmission infrastructure is needed. The AESO also researches historical energy intensities
for the industrial, oilsands, residential, farm and commercial sectors to adjust for future load
patterns. In addition, a growing focus on customer consultation helps the AESO incorporate
the most current information in estimating overall system needs. This includes ongoing
research into oilsands recovery, industrial processes and cogeneration requirements
and other end-use studies.
The projects identified in this LTP will not only help deliver the power Albertans need and
facilitate the reliability of the provincial transmission system, but will also increase the
efficiency of the transmission system. At the same time, transmission projects will remove
existing geographic constraints on generation of all forms, including renewable sources such
as wind, hydro and biomass. This will ensure electricity can move from where it is produced
to where Albertans need it.
The following sections of the LTP provide background, set the context, explain the planning
process, provide updates to the projects identified in the 2009 Long-term Transmission
System Plan (2009 LTP), including those subsequently designated as Critical Transmission
Infrastructure (CTI) and bulk and regional projects, and provide information on additional
elements directly linked to maintaining a safe, reliable and secure transmission system.
The AESO is obligated to act in the public interest in developing the LTP. Government policy
is also a key consideration in developing the Plan and should government policy change,
the AESO would need to reflect those changes, reviewing and modifying the Plan accordingly.
1.0 Introduction
PagE 15
2.0Background
2.1 role of the Aeso
The AESO was created through legislation in June 2003 as an amalgamation of the Power
Pool of Alberta and the Transmission Administrator. Its mandate is to plan and operate
the transmission system in a safe, reliable and economic manner, as well as to operate and
facilitate the wholesale electricity in a manner that is fair, efficient and openly competitive.
The AESO is a not-for-profit organization that acts in the public interest and by legislation
cannot own any transmission, distribution or generation assets. The duties and
responsibilities of the AESO are defined in the Province of Alberta Electric Utilities Act (EUA)
and the Transmission Regulation (T-Reg). The AESO is governed by an independent board
comprised of individuals appointed by the Minister of Energy.
The key duties and responsibilities of the AESO are to:
n Ensure the safe, reliable and economic operation of the Alberta Interconnected
Electric System (AIES).
n Operate the power pool and facilitate markets for electricity in a manner that
promotes fair, efficient and open competition.
n Provide transmission system access service via a tariff.
n Manage and recover the costs associated with line losses and ancillary services.
n Determine the future requirements of the AIES, develop transmission plans over
long-term horizons that identify the transmission system enhancements needed
to meet those requirements, and make the necessary arrangements to implement
those enhancements.
2.0 Background
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AESO Long-term Transmission Plan
1 See s. 10(1)(a) of the T-Reg for a full listing of requirements for the LTP.
The AESO is required by the T-Reg to prepare and maintain a transmission system plan that
projects, for at least the next 20 years1, system conditions and requirements. Additionally,
the AESO must plan a transmission system that is available in advance of need. These
legislative provisions mean that the AESO must take a long-term view, adjusting for
short-term changes, and focusing on directional system requirements to meet the
long-term vision for electrical infrastructure.
The Long-term Transmission Plan (filed June 2012) must take into account technical
considerations, reliability standards and operating and planning criteria which provide
for reliability and a well-functioning electricity market. In addition, other factors such as
government policies, forecast load growth, generation development, technological advances
and environmental impacts are considered. The details of the AESO’s obligations related to
transmission are noted in the Objectives of the LTP section on the following page.
The Alberta government’s Provincial Energy Strategy sets out an integrated vision for the
continuing development of the province’s energy resources. It also identifies the urgent
need to strengthen the transmission system to avoid barriers to economic development
and enable development of Alberta’s low-emission generation resources. The strategy calls
for a review and streamlining of the regulatory process for siting new transmission, while
ensuring stakeholders continue to have a voice in the process. The strategy is an important
consideration in the AESO’s development of a transmission system that will continue to benefit
all Albertans. The AESO’s transmission planning initiatives are consistent with the Provincial
Energy Strategy, which identifies upgrading and expanding the province’s transmission
system in advance of need as an urgent priority. Another important objective of the LTP
is to identify transmission infrastructure that will provide long-term support of the regional
transmission and access to other jurisdictions.
2.0 Background
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objectives of the ltP
The provisions of s.8 and s.15 of the T-Reg inform, to a large extent, what the AESO views
as the objectives of the LTP. These include:
n Plan for transmission facilities to meet anticipated future demand for electricity,
generation capacity and appropriate reserves to meet forecast system load.
n Plan for transmission system expansion to meet future load growth, addressing
the timing and location of future generation additions including areas of renewable
or low emission generation.
n Make an assessment of the transmission facilities required to provide
for efficient and reliable access to jurisdictions outside Alberta.
n Make an assessment of transmission facilities required to:
– Improve transmission system reliability.
– Support a robust competitive market.
– Improve transmission system efficiency.
– Improve operational flexibility.
– Maintain options for long term development of the transmission system.
The T-Reg provides some latitude for exemptions to these objectives and the consideration
of non-wires solutions as options in very limited circumstances; however, the objectives of
the LTP are clearly defined.
The AESO’s objectives related to reliability require compliance with Alberta Reliability
Standards (ARS) and target system expansion that provides grid operation with no
congestion under normal operating conditions and the capability to access larger markets.
Additionally, the AESO has objectives related to restoring the import/export transmission
capability of the existing interties to their 2004 rated capacity levels.
While the focus on transmission planning is to provide transmission access for generation
and load connections resulting in system growth, the LTP also includes the development of
system enhancement infrastructure intended to connect interregional transmission and allow
Alberta to operate effectively with other jurisdictions or markets.
2.0 Background
PagE 18
AESO Long-term Transmission Plan
The 2009 LTP identified transmission infrastructure essential to the long-term reliability
and sustainability of the provincial grid. The subsequently defined Critical Transmission
Infrastructure (CTI) projects are imperative to relieve congestion, provide connections
to the major transmission hubs in Alberta, connect regional loads and generation, reduce
transmission system losses and support long-term economic investment and growth. The
development of CTI projects in a proactive fashion removes investment uncertainty around
transmission access for both generation and load and supports an uncongested, competitive
market. Bulk system expansion is also required to link regional developments and support
continued economic growth in Alberta.
Although this LTP provides a 20-year assessment, to comply with Alberta Reliability
Standards the AESO must demonstrate the transmission system is planned in the 10-year
horizon such that:
n It can be operated to accommodate forecast load and generation scenarios
without interruptions when all transmission facilities are in service (TPL-001).
n It can be operated to accommodate forecast load and generation without
interruptions following the loss of a single element (TPL-002).
n When system simulations indicate an inability to meet the above requirements,
the AESO must develop transmission enhancements to achieve the required
performance (TPL-001 and TPL-002).
n It can be operated to accommodate forecast load with controlled load interruption
or removal of generation following the loss of two or more elements (TPL-003).
n It has been evaluated for the risks of extreme events (TPL-004).
The AESO operates the AIES to stay within acceptable limits during normal conditions, to
perform acceptably after credible contingencies, to limit the impact and scope of instability
and cascading outages when they occur, to ensure facilities are protected from unacceptable
damage by operating them within facility ratings, and to restore system integrity promptly if
it is lost. The system must supply the aggregate electric power and energy requirements of
electricity consumers, taking into account scheduled and reasonably expected unscheduled
outages of system components. These criteria define how the system is planned to operate
reliably and safely.
The LTP must also address criteria outlined in regulations related to telecommunications and
certain market and operational products and services (i.e., ancillary service (AS), transmission
must-run (TMR), transmission congestion management (TCM), etc.) used to directly support
the safe, reliable and efficient operation of the transmission system.
2.0 Background
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AESO Long-term Transmission Plan
Section 1 of the EUA defines transmission facilities and transmission system to include
telecommunications as follows:
bbb) “transmission facility” means an arrangement of conductors and transformation
equipment that transmits electricity from the high voltage terminal of the generation
transformer to the low voltage terminal of the step down transformer operating phase
to phase at a nominal high voltage level of more than 25,000 volts to a nominal low
voltage level of 25,000 volts or less, and includes:
(i) transmission lines energized in excess of 25,000 volts,
(ii) insulating and supporting structures,
(iii) substations, transformers and switchgear,
(iv) operational, telecommunication and control devices,
(v) all property of any kind used for the purpose of, or in connection with,
the operation of the transmission facility, including all equipment in a
substation used to transmit electric energy from...
ccc) “transmission system” means all transmission facilities that are part
of the interconnected electric system.
In order to capture and respond to changing system conditions, the AESO collects information
and evaluates need over three key periods: (1) over the short term or two years, typically
focused on regional needs; (2) over a 10-year horizon identifying medium-term needs,
addressing both bulk system and regional projects; and (3) up to a 20-year timeline indicating
long-term developments, typically aimed at the bulk system enhancements. The transmission
planning process involves frequently evaluating changes to the system that are required at
the regional, bulk and interconnected levels in response to changes in information.
Strategy andDirection
Policy andEconomic
Framework
Load andGeneration
Baseline
ScenarioAnalysis
Plan theSystem
Stress Testthe Plan
FinancialEvaluation
AESO BoardApprovalof Plan
AUC Filingof Plan
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Figure 1: long-term plan process
2.0 Background
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AESO Long-term Transmission Plan
2.2 VAlUe of trANsmissioN
The AESO is charged with the responsibility for planning the transmission system to ensure
adequate transmission capacity is in place in advance of need. In Alberta’s deregulated,
single price, wholesale electricity market, this means that transmission plans must allow
all generators to have equal opportunity to fully compete in the market and allow all loads
to withdraw power whenever and wherever it is required. A lack of transmission capacity
should neither hinder economic development decisions, nor determine winners or losers in
the wholesale electricity market. Only an adequate, open, non-discriminatory transmission
system can achieve these objectives.
Throughout North America, there are a number of electricity delivery models ranging from
localized delivery systems within a municipal service territory or industrial system to fully
integrated grids over large balancing authorities. While localized delivery systems may offer
efficiencies due to integrated systems and balances of load and generation, there are greater
economies of scale available in larger market systems. Transmission is critical to securing
the benefits of large-scale integrated grid models. While some may argue that distributed
generation can provide an alternative solution to large-scale generation, this is refuted by
two main points: (1) transmission is the low-cost element in the total cost of electricity,
supporting a competitive generation network, and (2) generation at the local, or any level,
cannot be a full substitute for transmission because it is less available, and therefore less
reliable, and can lead to issues of local market power.
The value of transmission is measured in comparison to the value of economic development
that it supports and also in comparison to the next alternative.
The economy of Alberta, as measured by Gross Domestic Product (GDP), is expected
to grow strongly over the next decade. The investment and development associated
with this economic growth is dependent upon having a reliable transmission system that
can serve the needs of growing businesses and industries. Investors assume adequate
transmission capacity will be available to accommodate their plans for development.
The Conference Board of Canada estimates that Alberta GDP in 2014 will be $396 billion
(2014 dollars). This strong GDP growth translates to a significant capital investment in Alberta
that provides both direct and indirect benefits to Albertans through employment, services,
tax revenues, and resource rents (royalties). As Table 2.2-1 illustrates, over $180 billion of
investment has been identified across multiple sectors for projects that have recently been
completed, are currently under construction, or are proposed to start construction within
the next two years.
2.0 Background
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AESO Long-term Transmission Plan
table 2.2-1: alberta Finance and Enterprise inventory of major projects (april 2011) valued at $5 million or greater
number of value of projects Fraction of total Project sector projects ($ millions) project expenditure
Agriculture and related 8 $238 <1%
Biofuels 12 $1,450 1%
Chemicals and petrochemicals 4 $119 <1%
Commercial/retail 55 $8,478 5%
Commercial/retail and residential 8 $2,668 1%
Forestry and related 7 $267 <1%
Infrastructure 280 $18,052 10%
Institutional 123 $7,616 4%
Manufacturing 6 $665 <1%
Mining 5 $4,945 3%
Oil and gas 7 $1,440 1%
Oilsands 61 $109,604 58%
Other industrial 6 $1,480 1%
Pipelines 29 $7,516 4%
Power 39 $13,704 7%
Residential 87 $4,760 3%
Telecommunications 2 $656 <1%
Tourism/recreation 94 $3,894 2%
total 833 $187,549 100%
Source: Alberta Finance and Enterprise
2.0 Background
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AESO Long-term Transmission Plan
The transmission development recommendations in this LTP address a 20-year horizon and
leverage the economies of scale of building large-scale transmission now to support the
system today and into the future. There are significant economic and regulatory efficiencies
to be gained from sizing facilities for anticipated demand 20 to 30 years into the future. This
approach avoids having to repeatedly expand existing transmission corridors or create new
corridors to add small incremental capacity to the system to meet demand growth over time.
Building in advance of need leverages the economies of scale that recognizes transmission
infrastructure has an investment lifespan of more than 40 years.
Transmission value is created by investing in backbone infrastructure today that is designed
to link regional hubs, relieve congestion, satisfy operational and reliability objectives internally
and across other balancing authorities, and support large-scale growth in the province.
The CTI projects are consistent with a value assessment that recognizes the benefits of
infrastructure designed to reduce congestion and to support large-scale growth in Alberta
over a long-term horizon.
As Alberta grows and develops its vast bounty of natural resources, demand will increase
significantly and the transmission system must evolve in anticipation of this demand.
Moving from a 240 kV system to a 500 kV backbone as new upgrades are built will provide
significant near-term benefits by alleviating transmission congestion and will enable efficient
system operation for decades to come and allow Alberta to keep pace with world demand
for its resources.
2.0 Background
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Decisions made by those investing in new sources of generation are based in part on having
the confidence that they can transmit the electricity they generate to the market and ultimately
to consumers. For business and industry, decisions on whether to locate in Alberta and to
expand existing operations require reasonable assurance of access to an adequate supply
of electricity at reasonably predictable and stable future prices. The availability of a robust
transmission system provides investors and generation developers with confidence that they
will be able to connect to the grid and provide their electricity to the market.
Transmission development plans also recognize that Alberta is part of, and connected to,
the North American electricity grid. Transmission interties connecting Alberta to neighbouring
systems are an essential part of a reliable electricity system and a competitive market.
Interties provide the ability to import power into Alberta when economically attractive and
export power when supply is excess to the needs of Albertans. Albertans benefit from these
interties by gaining access to potentially lower-priced electricity. Revenues received by
exporters also attract more investment and increase competition.
The value of transmission has been studied in markets throughout the world and is based
on several key elements:
1. Value associated with reliable service – measured occasionally as the value
of lost load.
2. The avoided cost of transmission losses as transmission improvements are
put in place.
3. The value of supporting a competitive generation market – usually assessed against
some measure of local market power or the incremental increase in the prices
for electricity as generation is stranded due to transmission congestion.
4. The avoided cost of temporary non-wires solutions like TMR or TCM.
5. The enabling of expansion and connection opportunities for fuel diverse
generation resources.
6. Provides insurance against contingencies during abnormal system conditions such
as fuel supply disruption, extended loss or outage of a baseload power plant, or
prolonged weather related events resulting in the failure of a critical transmission
line in the grid.
7. In Alberta, the ability to meet the Provincial Energy Strategy objectives of harnessing
renewable energy resources.
2.0 Background
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AESO Long-term Transmission Plan
The transmission system must provide sufficient capacity so electricity can move without
constraint from where it is produced to where it is needed to power homes, businesses,
farms and industries throughout the province. New infrastructure must be in place before
demand arises so investment, market access and economic development are not
compromised. A more detailed analysis and discussion on the Value of Transmission
is provided in Appendix K, Part 1.
$1,000
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$800
$700
$600
$500
$400
$300
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$100
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800
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Estimated cost of constrained down generation ($ millions)
Cost of transmission must-run ($ millions)Vo
lum
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2008 2009 2010
Volume of transmission must-run (GWh)
Volume of constrained down generation (GWh)
Figure 2.2-1: Actual and estimated cost of transmission congestion events equivalent to those observed from 2008 to 2010
Data from recent years illustrates the cost of transmission congestion to consumers.
Figure 2.2-1 illustrates the estimated costs to consumers for levels of congestion seen from
2008 to 2010. This is based on an analysis of how much the price of power increases due
to a transmission system constraint that results in higher priced generation being dispatched.
This analysis also includes the costs associated with TMR. For levels of constrained
generation similar to those observed over the past three years, it is estimated that energy
charges to consumers are nearly $1.6 billion higher than they would be in the absence of
constrained generation.2 Section 3.6.7 of the LTP provides additional analysis of TCM and
the cost of congestion to the wholesale electricity market.
2.0 Background
2 This analysis is a theoretical statistical illustration only, based on unusually high constraints observed from 2008 to 2010 including a rare storm event and temporary but significant construction activity related to transmission enhancement. It is not a forecast but it is designed to demonstrate the potential extreme impacts on the market should transmission requirements be underestimated.
PagE 25
AESO Long-term Transmission Plan
2.3 PlANNiNg for UNCertAiNty
Long-term transmission planning is inherently uncertain given the time horizons involved,
the diversity of generation that may or may not be built, the importance of locational siting
and the critical importance of timing. Transmission investment decisions must anticipate
need decades into the future because transmission infrastructure has an investment lifespan
of 30 to 40 years and new developments require five to eight years to plan and build. In
addition to reliability requirements, transmission plans must consider trends in economic
development, population growth, technological advancement and environmental regulation,
as well as trends in neighbouring jurisdictions in order to arrive at robust solutions that
stand the test of time. Given the large number of variables involved, accurate and complete
forecasting of load and generation growth over the long economic life of transmission assets
is difficult. Decisions must be made through the use of scenario analysis to arrive at plans
that can adapt to a broad range of potential future outcomes. This is also why the planning
process needs to be reviewed and updated on a regular basis.
Prior to deregulation, integrated utilities planned both generation and transmission
development to meet anticipated demand. While there was significant long-term uncertainty
associated with the timing and location of new load, the timing and location of new
generation was under the control of the utility system planners. In Alberta’s deregulated
market, transmission planning is characterized by additional uncertainty because the timing
and location of new generation additions and retirements are private investment decisions
made independently of the AESO.
With the large number of variables that must be considered, the AESO’s transmission
plans must be robust and flexible so that the configuration of the system does not constrain
future economic development. In recognition of this uncertainty, the 2003 Transmission
Development Policy (Transmission Policy) provides direction to the AESO to be proactive
in its planning and build transmission in advance of need since market signals will not
provide timely indicators for development given the long lead time associated with
transmission projects. The use of project staging enables prudent timing of transmission
developments ensuring consumers receive maximum value from transmission investments
by timing the construction of incremental phases of projects to align investment with
anticipated need dates.
2.0 Background
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AESO Long-term Transmission Plan
As policies evolve and fuel source preferences change over time, adequate transmission
capacity facilitates changes in the generation fleet as investors and generation developers
choose new types and locations of generation based on the availability of new fuels. Wind
and hydro power provide low cost, carbon free energy that complements thermal sources
such as natural gas and coal. A diverse mix of generation sources provides economic and
environmental benefits which is a key objective of the Transmission Policy and, subsequently,
transmission planning.
The long lead time and economic life associated with transmission projects results in an
asymmetric risk profile for transmission development – the cost of building insufficient
transmission capacity far outweighs the cost of building excess transmission capacity.
If forecasts for load and generation evolve more slowly, the AESO believes it is a reasonable
assumption that loads and generation will only be delayed, eventually catching up to where
the transmission can be fully utilized.
If future expectations of need turn out to have underestimated the amount of transmission
capacity required, the consequences are much greater. Economic development may be
deferred or reduced due to the lack of sufficient transmission capacity. Increased congestion
will undermine the efficiency of the wholesale market, increasing the delivered cost of
power to consumers, reducing the competitiveness of generators and potentially discourage
the entry of new market participants. System inefficiency will intensify with increased line
loading, which will result in greater losses and expanded reliance on non-wires solutions
such as TMR to compensate for inadequate transmission capacity in constrained areas.
The sum of these consequences is far greater than the fixed cost associated with building
excess transmission capacity to meet future anticipated needs with the ultimate penalty
being reduced system reliability.
In determining the appropriate size of incremental transmission additions, the most effective
hedge against future uncertainty is to plan for the most likely demand and generation growth
scenarios to ensure sufficient capacity margin and minimize the significant consequences
associated with insufficient transmission capacity. The AESO takes a measured approach to
determine solutions that are practical, prudent and cost effective. Consideration for staging
projects and defining milestones are employed where appropriate. This follows the direction
of the current T-Reg, Part 3, Transmission System Criteria and Reliability Standards.
2.0 Background
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2.4 trANsmissioN PlANNiNg sCeNArios AND seNsitiVities
The assessments begin with base case models of the transmission system that include
the load and generation forecasts for 2012, 2015 and 2020. Loads are based on the
AESO’s most recent load forecast and the generation additions are taken from the baseline
generation scenarios identified as GS2 and GS3. These scenarios have the same general mix
of coal, gas and other generation with the only variable being the location of some of the
gas-fired generators. GS2 has more gas-fired generation in the south, whereas GS3 has
more in the north. In addition to the forecast load and generation, the base case models
also include the planned topology projects based on the 2009 LTP and are enhanced
by the Needs Identification Documents (NIDs) prepared since the 2009 LTP was released.
These are described to a greater degree in Section 3.5 of the LTP.
Within the analysis there is delineation between the two types of variation analysis
undertaken: scenario analysis tests the transmission system under alternate outlooks,
whereas sensitivity analysis tests the changes resulting from varying one specific
assumption. An example of scenario analysis is the consideration of alternate generation
scenarios, as discussed in Appendix E. Sensitivity analysis tests a specific assumption such
the development of an influential generator or increased rate of load growth. The sensitivities
considered are addressed in Section 4.4.5. Typical assumptions would include alternate
generation scenarios manifesting in the next 10 years, certain major generator projects not
moving forward as planned, and loads higher than anticipated in the northeast. Overall, the
purpose of the scenario and sensitivity analysis is to determine the impact of general trends
and certain assumptions on the proposed transmission system.
The scenarios and sensitivity analysis were conducted on the bulk system for the year 2020
only. Only single contingency and common tower failure events were studied and only for the
lines rated at 240 kV and above.
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Alternate generation scenarios
This analysis tested the impact on the proposed system assuming that one of the non-base
scenarios occurs.
Three new cases were created using the 2020 summer peak case. Generator merit
order dispatches for each of the scenarios were established and stress cases for single
contingencies were developed assuming critical generators were offline. Common tower
failure contingencies were run for the non-stressed cases (three base cases without
additional generation offline). Refer to Section 3.5 and Appendix E for additional detail.
sensitivities if generation projects do not proceed as anticipated
In the baseline generation scenarios there are specific large generation projects proposed
to be added to the AIES by 2020. Some of these projects could have a significant impact
on the system if they do not proceed. For study purposes only, this analysis tested the
impact on the system of these generation projects not being developed as proposed.
Specifically for this analysis the generators assumed to not proceed are:
1. The Swan Hills coal gasification project (375 MW) in the Northwest region.
2. The Saddlebrook combined cycle gas generator project (350 MW) in the South region.
3. Five proposed cogeneration projects totalling 340 MW in the Northeast region.
sensitivities affecting Northeast region load
Load development in the Northeast region is uncertain and, should it increase faster than
expected, could impact the needed supply into that area of the province. The predicted
oilsands production used in the forecast for the Northeast was about three million barrels
per day by 2020. If all recently announced projects proceed, this would result in production
levels at about eight million barrels per day by 2020, providing an indication of the significant
upside potential of the forecast.
The transmission infrastructure projects recommended in the LTP include the identification
of several key metrics. Imbedded in the analysis, evaluation and determination of need, the
AESO planners review the respective in-service dates, estimate project costs, and define the
key driver or drivers behind the projects. The most prominent drivers requiring mitigation or
response are customer connection requests, system capacity, operating limits, and system
reliability concerns. Section 4.0 of the LTP describes the principal drivers behind each
project. In general, these drivers are captured in the following terms – reliability, reduction
of congestion, removal of constraints, voltage fluctuation, frequency excursion, thermal line
loading, reduced line losses, reduced dependency on non-wires short-term solutions, and
the ability to fulfil load and generation connection requests.
2.0 Background
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3.0AESO Planning Process
The Long-term Transmission Plan (filed June 2012) – also referred to as the LTP or the Plan
– provides an opportunity to update and validate the bulk, regional and intertie transmission
levels identified in the 2009 Long-term Transmission System Plan (2009 LTP). Overall, this LTP
results concur with the key elements of the 2009 Plan in terms of transmission infrastructure
recommendations; however, there are some changes recommended in terms of staging for
some of the Critical Transmission Infrastructure (CTI) projects, as well as some differences
in regional projects involving scope changes, the addition of new projects and the deletion
of others. As part of the refresh of the LTP, the AESO has also conducted a review of the
current estimates of each proposed project. Overall, this LTP substantiates, and continues to
emphasize, the need for additional transmission development in the short-term and mid-term
in response to the continued growth in Alberta’s economy.
The LTP transmission recommendations are evaluated using the baseline load and generation
growth forecasts, as well as an assessment of transmission projects outlined in previous
LTPs, and updated with NIDs filed with the Alberta Utilities Commission (AUC). Using these
baseline assumptions, the transmission system is stressed for various load conditions (winter
peak, summer peak, and summer light) as well as for various generation scenarios (gas
generation locations and the impact of variable generation). Finally, the system is evaluated
using various intertie assumptions (maximum flows for import and export, economic flows
and no flows).
As noted previously, the transmission system is first assessed to determine what physical
wires solutions are required and when they will be needed. Should there be a disconnect
between the assessed need date and the anticipated in-service date (ISD), the AESO
will determine whether any non-wires or operational solution is required in the short term,
typically considered to be 24 months. System performance is then evaluated to 2020 and
finally out to 2029. These study periods aid the AESO in assessing and validating the need
for transmission infrastructure and tests the staging of projects to ensure they remain timely
and are available in advance of need. They also ensure the ISD is practical.
The planning process is complex and takes into account multiple input assumptions, all with
varying degrees of uncertainty, which culminate in running numerous scenarios, sensitivities
and stress tests. It is further complicated by the fact that Alberta’s is a large interconnected
system where the location of either new load or generation can create consequences in
other parts of the system.
3.0 AESO Planning Process
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3.1 stAKeholDer CoNsUltAtioN ProCess
Stakeholder consultation with the general public, elected officials, special interest groups
and others provides the AESO with a broad perspective and valuable input used to improve
transmission planning. In 2010 and 2011 to date, the AESO has carried out extensive public
consultation on various proposals to develop the transmission system in many locations
throughout Alberta. This consultation includes the exploration of geographic options,
potential technologies and environmental and social considerations. Stakeholders were
engaged through various methods and their input helped form the transmission system
development identified in the LTP.
Over 3,600 stakeholders and members of the general public participated in approximately
70 open houses and group meetings as part of the transmission system development
consultation process during 2010 and to date in 2011. Statistics regarding the AESO’s
consultation activities are presented in Table 3.1-1.
Stakeholders are identified as:
n market participants,
n residents, occupants, landowners and businesses,
n elected and administrative government officials at local, municipal
and provincial levels,
n customers,
n First Nations and Métis,
n advocacy and environmental groups.
Based on the following consultation principles, the AESO used a variety of methods to notify,
consult and engage members of these groups including mailings, newspaper and radio ads,
news releases, website postings, meetings and presentations, correspondence (email and
mail), telephone, industry sessions and open houses.
Feedback indicates there is a general recognition that Albertans’ growing demand for
additional power must be addressed and that transmission reinforcement is necessary.
A common view held by many stakeholders is that they prefer reinforcements with higher
capacity to accommodate long-term growth that mitigates the need for repeatedly returning
to build more transmission lines in the future. Many stakeholders have voiced opinions to
the AESO that if they must have towers on their land, they would prefer fewer high-capacity
towers to more smaller towers with lower capacity.
3.0 AESO Planning Process
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the Aeso’s stakeholder engagement Principles
Roles and participation in decision-making
n The AESO makes the decisions on changes and the timing of those changes.
n The AESO uses the experience and expertise of stakeholders to improve the
quality and implementation of decisions.
n The AESO determines the level of consultation needed on an issue, based on
the perceived significance and impact on stakeholders and the time available.
n All stakeholders have the right to comment on the AESO’s plans, decisions
and actions.
The process of making decisions
n All potential changes progress through consistent defined stages from problem
identification to implementation and review.
n The AESO’s consultation process and the rationale for the AESO’s decisions
are transparent.
Informing stakeholders
n All stakeholders have the right to be informed of the AESO’s direction, plans,
status of issues and decisions in a timely manner.
n The AESO communicates a consistent position on potential changes that
resolves the perspectives across the AESO’s functions.
Continuous improvement
n The AESO measures the success of its engagement process, and the
effectiveness of resulting changes, to improve its future performance.
3.0 AESO Planning Process
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table 3.1-1: aESo consultation statistics: 2008-2011 (to date)
2008-2009 2010-2011 (to date)
open houses 134 70
attendees registered 9,123 3,602 at open houses
Powering Albertans 2008 Spring edition 2010 Spring edition magazine distributed – 1.2 million copies mailed – 700,000 copies mailed to Calgary to Alberta homes and Edmonton homes; 600,000 – Additional copies at all open copies delivered via newspaper houses (approximately 2,000) insert to other communities – Mailed/distributed to over across Alberta
150 organizations throughout 2011 Spring edition
the province including: – 700,000 copies mailed to Calgary
libraries, chambers of and Edmonton homes; 600,000
commerce and town councils copies delivered via newspaper
– Teachers across Alberta insert to other communities requested 1,200 copies
across Alberta 2009 Spring edition – 1.3 million copies delivered via newspaper insert at the beginning of March
aESo dvds 2008 Spring editiondistributed – Distributed at 12 open houses
– Over 120 copies distributed to schools and libraries
Presentations and 64 84 discussions with municipalities
3.0 AESO Planning Process
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3.2 DetermiNiNg NeeD
Since release of the 2009 LTP, Alberta has experienced significant changes to the economy
including broadly fluctuating commodity prices, availability of credit, changes to
environmental policy and generation announcements.
Despite the economic slowdown, economic fundamentals remain strong for Alberta and
show a long-term growth in demand of 3.2 per cent annually for the next 20 years. The
economic recovery in Alberta continues as confidence in all sectors appears to be strong.
The key driver of the Alberta economy continues to be expected investment in oilsands,
which relies on the availability of significant electrical infrastructure. In addition, with the
expected retirement of coal-fired generation, the need for transmission remains to support
the replacement of this retiring generation and anticipated additional or replacement
generation. This LTP contains many of the same assumptions outlined in the 2009 LTP,
although some have changed to reflect policy and recent generation announcements:
n Historical system energy consumption grew from 38 terawatts (TWh) in 1990
to 72 TWh in 2010 (or 3.2 per cent average annual growth), and is expected
to nearly double again by 2029 from 72 TWh in 2010 to 132 TWh in 2029.
n System demand for transmission remains regionally diverse.
n Recent climate change announcements by the federal government to stipulate a
clean coal obligation change the outlook for coal and the likely increased reliance
on gas as a fuel source for generation.
n Recent announcements by generators, specifically those with power purchase
arrangements (PPA) in place, reflect the potential for early retirement of the
coal-fired generators.
n Some changes in generation outlook are also noted including scenarios related
to the timing of the Sundance 7 in-service date, recognition of the H.R. Milner
expansion and the deferral of Slave River Hydro generation.
Transmission planning is an ongoing process intended to reflect changes in the economy,
commodity prices, industrial projects, customer connection requests and generation
development in determination of need. While the baseline forecast has been adjusted to
accommodate these changes since the 2009 LTP, the fundamental need for transmission
system developments and regional upgrades remains valid to replace aging infrastructure
and resolve issues related to an increasingly constrained transmission grid.
3.0 AESO Planning Process
PagE 34
AESO Long-term Transmission Plan
The expected change in the diversity of the generation fleet over time will have some impact
on future transmission planning as well. By 2020, the AESO expects total installed generation
capacity to grow to approximately 19,000 megawatts (MW). Today’s supply is weighted
towards a coal-fired and gas-fired mix. However, it is anticipated that with the retirement of
coal at the later of PPA expiry or facility life (typically considered 45 years), natural gas-fired
generation will be the fuel of choice to replace coal. Gas plants are an economically viable
alternative and are useful in backing up the increasing amount of intermittent resources
on the grid. As gas is more locationally flexible than some other fuel sources, the AESO
will test its transmission plans using various locational options.
Despite changes to load and generation expectations, the key factors influencing
this LTP include many of the same key components introduced in the 2009 LTP:
n Need for CTI to strengthen the backbone of the transmission system, resolve
current operational limitations and support long-term provincial growth.
n Ongoing load growth despite recent short-term economic slowdown.
n Additional investment in generation continues, ranging from new wind facilities
to the addition of new gas generation and future cogeneration operations.
Recognition of the environmental policy pressure on coal to meet clean standards,
which could drive the possibility of new gas-fired generation as a replacement.
n Further evaluation and assessment required of the criteria and future need
determination for intertie development to support reliability, load and market
objectives fulfilled by access to larger markets. This LTP reflects the current
analysis underway related to integrating new merchant transmission onto the grid
(i.e., Montana-Alberta Tie Line).
n Recognition of the supporting interim non-wires solutions, operational protocols
and services in place to support transmission infrastructure, market dispatch
and system reliability.
3.0 AESO Planning Process
PagE 35
AESO Long-term Transmission Plan
3.3 loAD foreCAst ProCess
Establishing a robust and credible Alberta load forecast is an essential first step in determining
need for future transmission builds. The baseline load forecast used for this LTP was
published in February 2010 and is referred to as the Future Demand and Energy Outlook
(2009-2029) (FC2009). The FC2009 is reassessed as new information becomes available
to ensure it remains valid and reasonable.
Key inputs into the Alberta Internal Load (AIL) energy and load forecast are Alberta gross
domestic product (GDP), population growth, oilsands production, personal disposable
income and detailed project and distribution facility owner future load information.
To get the most accurate information, the AESO relies on third-party experts such as
The Conference Board of Canada, Canadian Association of Petroleum Producers and IHS
Global Insight. These forecasts are cross-referenced for consistency and reasonableness.
The FC2009 forecast used econometric, top-down, and bottom-up models to forecast
electricity usage on a customer sector basis. This methodology provides a consistent and
balanced approach to load forecasting through the use of a combination of fitted statistical
models, historical data, third-party economic forecasts and customer-specific information.
The AESO’s models are consistent with industry standards for forecasting electricity demand
and are customized to fit Alberta’s unique characteristics. A more detailed description of the
load forecasting process can be found in Appendix D. Figure 3.3-1 provides an overview of
the load forecast development process.
Hourly load shape by point of delivery (POD)
20-year hourly forecast by POD
Input to generation scenarios/forecast
Regional, provincialAlberta internal
load (AIL) forecast
Used in regionalstudies and bulksystem studies
Onsite generation forecast
Alberta Interconnected Electric System (AIES) load forecast, behind-
the-fence (BTF) forecast
Billing determinants (Tariff)
Economic variables(GDP, population, etc.)
Residential, commercial, farm, industrial and oilsands
energy – 20 year forecast
Project specific information
Figure 3.3-1: load forecast development process
3.0 AESO Planning Process
PagE 36
AESO Long-term Transmission Plan
Figure 3.3-2: 2010 AIL energy, including losses, 71,723 GWh
44% Industrial (without oilsands) 31,525 GWh
19% Commercial 13,748 GWh
16% Oilsands 11,134 GWh
13% Residential 9,071 GWh
6% Losses and other 4,537 GWh
2% Farm 1,708 GWh
3.0 AESO Planning Process
The AESO forecasts five customer sectors separately to create the annual energy forecast.
The five sectors are: industrial (without oilsands), oilsands, commercial, residential and farm.
Each sector’s energy demand is driven by different factors. Figure 3.3-2 and Figure 3.3-3
depict historical Alberta Internal Load (AIL) energy consumption by each of these customer
sectors. Historically the industrial (without oilsands) sector contributed the most to provincial
consumption; however, energy consumption from the oilsands sector has grown dramatically
over the last 10 years.
Alberta Internal Load (AIL) is the total electricity consumption including behind-the-
fence (BTF) load, the City of Medicine Hat and losses (transmission and distribution).
Alberta Interconnected Electric System (AIES) load is the electricity consumption
excluding BTF load and the City of Medicine Hat.
In forecasting AIL load, the AESO includes and models all electricity loads connected to the
transmission system irrespective of where their generation supply comes from. Generation
assumptions are modelled to assess the impact on the system should on site generation
become a consideration. Sites with on site generation and/or cogeneration facilities can,
and often do, request connection to the grid in the form of a Demand Transmission Service
(DTS) for a portion of their on site load, offsetting any electrical supply interruption to
key industrial processes should their on site generation be compromised. It is, therefore,
important to model and plan for both the load and generation impacts this characteristic
produces. This is one of the reasons the AESO forecasts AIL load growth, not just AIES.
industrial (without oilsands): The sector is the largest customer sector, comprising
44 per cent of total AIL energy. The energy model is a regression model using Alberta mining
and oil and gas GDP as its primary driver. The industrial sector is highly dependent on the
health of energy exploration and development. The forecast of Alberta mining and oil and
gas GDP is from The Conference Board of Canada’s Provincial Outlook Long-term Economic
Forecast (2009) and Provincial Outlook Spring (2009).
PagE 37
AESO Long-term Transmission Plan
oilsands: In 2010, this sector comprised 16 per cent of total AIL energy. The model relies
on estimation from third parties of mining, in situ and upgrading production multiplied by
an intensity factor for each process. The intensity factors assumed in the forecast are based
on actual historical usage. The production forecast was based on the Canadian Association
of Petroleum Producers’ June 2009 Outlook.
commercial: This sector accounts for 19 per cent of total AIL energy and is a regression
model using the historical relationship between commercial energy and Alberta GDP.
The GDP forecast used was from The Conference Board of Canada.
residential: This sector is around 13 per cent of total AIL energy and is a function of
population and disposable income per person. Forecasts of population and disposable
income per person are from The Conference Board of Canada.
Farm: This sector is the smallest sector at two per cent of the AIL. The AESO used a 10-year
historical average annual energy calculation to forecast future electricity demand for this sector.
losses: Includes distribution and transmission losses and energy to Fort Nelson,
British Columbia through its connection to the AIES.
1967
1969
1971
1973
1975
1977
1979
1981
1983
1985
1987
1989
1991
1993
1995
1997
1999
2001
2003
2005
2007
2009
70,000
60,000
50,000
40,000
30,000
20,000
10,000
0
Ann
ual e
nerg
y (G
Wh)
Industrial (without oilsands) OilsandsCommercial Residential Farm
Figure 3.3-3: Historic annual AIL energy by sector, excluding losses (GWh)
3.0 AESO Planning Process
PagE 38
AESO Long-term Transmission Plan
3.0 AESO Planning Process
To create realistic hourly forecasts for the future, the AESO creates representative load
shapes for each point of delivery (POD) on the transmission system. There are 500 PODs
defined for the Alberta system. The historic load shapes are adjusted for anomalies, calendar
days and some weather effects. Adding all PODs for each hour creates the hourly AIL
forecast and the forecast seasonal peaks. Details of the FC2009 can be found in Appendix D.
The FC2009 is a long-run assessment of future load growth potential built on 20 to 30 years
of historical energy usage patterns. Short-term variability can be expected given economic,
capital investment and construction cycles. Assessing the robustness of the forecast in the
short term is useful to determine and validate model and/or forecast inputs, and to make
assessments to improve the process for future forecasts.
In the first five years, there is uncertainty due to short-term economic changes as well as
project timing and start-up rates. In the five to 10 year timeframe, uncertainty results from
potential longer-term economic fluctuations, project development, new technology and
technology improvements. In the 10 to 20 year timeframe, uncertainty will result from
new and improved technologies and significant broad policy changes.
The FC2009 includes the following key conclusions:
n Over the forecast period, peak demand growth is expected to average
3.3 per cent per year.
– From 2010 to 2015, peak demand is forecast to grow by 4.6 per cent.
– From 2015 to 2029, peak demand is forecast to grow by 3.1 per cent.
n The FC2009 load forecast is based on detailed analysis of key economic inputs
that affect the five different customer sectors in Alberta.
n 2008 and 2009 economic conditions slowed Alberta’s growth but all indications
point to resurgence in the economy and its primary driver, oilsands development.
n The FC2009 load forecast is a long-run assessment of future load growth in
the province. It is not meant to capture short-term variability, although the AESO
does use its short-run variance to assess the validity of assumptions in the
long-run forecast.
n Changes from the FC2007 forecast (used in the 2009 LTP) captured in the FC2009,
reflected a delay in load growth by one to two years by 2015 and 2020. The
Northeast region saw the largest change from FC2007 to FC2009, showing
a decrease of 1,000 MW by 2020; however, a significant 60 per cent increase
in load is still expected by 2020.
PagE 39
AESO Long-term Transmission Plan
3.4 geNerAtioN foreCAst ProCess
The second key input to the planning analysis is the creation of a solid forecast of anticipated
future generation capacity required to meet forecast load. In formulating this outlook,
consideration is given to available technologies as well as the timing, location and size
of facilities.
Creating the generation forecast includes determining the future supply gap between load
growth and future generation retirements in the province. It also includes assessing what
generation technologies, resources and projects are expected to be developed within the
wholesale market to facilitate adequate supply to meet future load.
This includes quantifying the magnitude and location of the resources that could fuel power
generation (i.e., location and size of resource) and assessing the attractiveness and timing
of each generation technology considering key drivers such as fuel costs, availability, capital
costs, and operating characteristics.
Further validation of key inputs to the generation forecast include reviewing the current
project list and generation queue, projects planned by developers, and the relative costs
of generation resources. The forecasts are validated through market simulation to ensure they
adequately meet load and generate market signals that would support the generation mix
development. They are further confirmed through consultation with customers and industry
representatives on an individual and broad group basis and through historical tracking.
20-year load forecastAnnual generation
capacity additions by location, type and size
Validate load adequacyand market signals with
generation forecast
Onsite generation forecast to
load forecast
Finalize generation forecast and scenarios
Used in regionalstudies and bulksystem studies
Available generation resources (technologies,
resources, costs)
High level outlook of generation development
Project specific information
Figure 3.4-1: generation forecast development process
3.0 AESO Planning Process
PagE 40
AESO Long-term Transmission Plan
Since the 2009 LTP was released, the following key changes affecting the generation
forecast have occurred:
n Environmental policy expectations at the federal levels in both Canada and the U.S.
dampen the expectation that additional coal (beyond Keephills 3) will develop before
2020. This is a change from a subset of the generation scenarios developed for the
2009 LTP that considered the development of additional coal-fired generation.
n Expectation of continued stable gas prices leads to the expectation of combined
cycle gas-fired generation filling the requirement for additional baseload generation
(along with cogeneration and wind). The AESO will continue to monitor this
assumption to determine if any changes are warranted.
n The location of combined cycle development is flexible. Project proponents are
developing a number of sites in southern Alberta. However, brownfield coal sites are
also attractive locations for combined cycle developments as land, permits, water,
an experienced workforce and infrastructure such as transmission are in place.
n Even though expectations about which technology will make up the majority of new
generation capacity have changed since the last LTP, regional capacity additions
have not changed drastically. While there has been a shift from the addition of coal
capacity to combined cycle capacity, the baseline generation scenarios in this LTP
are roughly equivalent to scenarios B3 and B4 used in the 2009 LTP. Scenario A2
referenced in the 2009 LTP is equivalent to the high cogeneration scenario (GS4) in
this LTP, while B5 referenced in the 2009 LTP is equivalent to the greenest scenario
(GS1) in this LTP. Refer to Appendix E for further information on the generation
scenarios used in this Plan .
n The development of wind generation continues to be a major uncertainty in
Alberta. The connection requests indicate a large amount of development
is being investigated in Alberta, but environmental policy uncertainty in Canada
and the U.S. leads to uncertainty on the green revenue stream for wind. The
elimination of Canadian federal subsidies also reduces the attractiveness of
this technology. The AESO’s baseline assumptions for wind development in
Alberta generally align with the moderate wind forecast included in the 2009 LTP.
A high wind scenario is assessed in this LTP and is considered an important scenario
in transmission planning and market development.
n Due to continued development in policy regarding carbon costs in our economy,
the AESO has reduced the expected price in the generation baseline from $60/tonne
to $30/tonne in 2020.
3.0 AESO Planning Process
PagE 41
AESO Long-term Transmission Plan
The following key principles form the foundation of the generation forecast:
n By 2020, total installed generation capacity is expected to grow to approximately
19,000 MW from the current installed generation capacity of approximately 13,000 MW.
n Natural gas-fired generation is anticipated to be the primary fuel choice for
generation developers.
n Coal retirement at 45 years or end of Power Purchase Arrangements (PPA),
per the federal government policy statement.
n Current provincial price on carbon of $15/tonne until 2014; expected to increase
post 2014.
n Amount of new wind generation still uncertain; future carbon value unknown.
n Peaking capacity will depend on the scale and timing of wind build out.
n Cogeneration growth will continue largely as a function of oilsands growth.
n Locational diversity of future gas generation to be tested.
n Future generation mix will largely depend on market and/or policy evolution.
n The transmission infrastructure contemplated in the LTP will facilitate development
of an efficient and diverse generation mix.
The generation forecast balances the accuracy of the information with the risk associated
with uncertain timelines. The next five years are fairly certain and the majority of generation
projects already have some plans in place. This makes the outlook for the market fairly
certain, with variation coming from the timing and viability of specific planned projects
and changes in fuel costs rather than changes to available technologies or policies. For
the five to 10 years following that, the generation technology options become broader
and the relative cost of each less certain. During this period, sensitivities on the specific
projects and the general generation mix may need to be considered.
For the longer term, 10 to 20 years from now, a shift from the current state must be
considered as investment drivers and technology choices are guaranteed to change.
When planning this far into the future, it is important to develop scenarios that consider
cases that could cause major changes from the baseline. Due to these uncertainties,
generation scenarios are created and taken into account in transmission planning
recognizing there will be time to readjust as necessary. Overall, this long-term forecast
acts as a high-level guide to where generation development is going and what sensitivities
should be considered.
3.0 AESO Planning Process
PagE 42
AESO Long-term Transmission Plan
3.5 system PlANNiNg AND reliAbility stANDArDs
Once the updated load and generation forecasts have been established, these inputs are fed
into the transmission planning models to create base case models, scenarios, sensitivities
and stress test cases. This analysis determines both short-term and long-term system
impacts and ultimately the assessment of transmission need to match the updated forecasts.
To assess the transmission system, the province is divided into five regions (see Figure 3.5-1).
The 2009 LTP identified six planning areas; however, for consistency, this LTP uses
five planning areas to align with the analysis in the AESO’s 24-Month Reliability Outlook.
This allows for a thorough assessment of the transmission system down to a voltage of
69 kilovolts (kV). The regional differentiation is based on the unique load and generation
characteristics of various parts of the province. In addition to the regional assessments,
the ability of the bulk system to move power between the regions is also assessed.
3.0 AESO Planning Process
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PagE 43
AESO Long-term Transmission Plan
South
Northwest Northeast
Edmonton
Central
Figure 3.5-1: transmission planning regions
3.0 AESO Planning Process
PagE 44
AESO Long-term Transmission Plan
3.0 AESO Planning Process
System reliability is assessed to comply with the Alberta Reliability Standards (ARS) and AESO
Transmission Planning Criteria. It identifies facilities that do not meet reliability performance
requirements during the planning horizons studied and proposes mitigation options. The
planning studies assess the performance of the bulk and regional transmission systems
relative to the standards over the planning horizon up to the year 2020, considers possible
transmission alternatives and develops a recommended transmission development plan.
table 3: alberta transmission reliability standards
tPl-001-aB-0 System performance under normal conditions
tPl-002-aB-0 System performance following loss of a single element
tPl-003-aB-0 System performance following loss of two or more elements
tPl-004-aB-0 System performance following extreme events
Approved September 23, 2009 Effective September 24, 2010
The AESO must demonstrate through assessment that the transmission system is planned
in the short-term (one to five years) and the long-term (six to 10 years) horizon so that it
can accommodate forecast load and generation without interruptions when all transmission
facilities are in service, and following loss of a single element (TPL-001 and TPL-002). When
system simulations indicate an inability to meet the above requirements, the AESO must
develop transmission enhancements to achieve the required performance.
The AESO must also demonstrate through assessment that the transmission system
is planned so that it can accommodate forecast load with controlled load interruption or
removal of generation following the loss of two or more elements (TPL-003). It must also be
evaluated for the risk of system performance following extreme events (TPL-04).
In assessing the ability of the system to meet future loads and generation, the AESO creates
base case models that include the load and generation forecasts for 2020, 2015 and 2012.
First, the year 2020 is assessed to determine what, if any enhancements are needed in
the long term. This analysis is performed in an iterative manner by including and removing
proposed transmission enhancements and supports planning for staging of projects.
The system is then studied for the year 2015 using the same iterative process to identify
components of preferred alternatives required in the short term and to again determine
opportunities for staging. Finally, studies are performed for 2012 to inform the AESO of
existing problems that need to be mitigated as quickly as possible and to help identify
the timing of enhancements. The 2012 assessment also identifies short-term operational
mitigation measures required until facility enhancements can be built. The results of this
analysis are reported in the AESO’s 24-Month Reliability Outlook report issued each year
(see Appendix B).
PagE 45
AESO Long-term Transmission Plan
3.0 AESO Planning Process
Sto
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h.
For this LTP, loads are based on the AESO’s FC2009 load forecast and the generation
additions are taken from the baseline generation scenarios identified as GS2 and GS3. These
scenarios have the same general mix of coal, gas and other generation and the only variable
is where generators are located. GS2 has more gas-fired generation in the south and GS3
has more in the northern part of the province.
In addition to forecast load and generation, the base case models include planned topology
projects based on the 2009 LTP and are enhanced by Needs Identification Documents
prepared since the 2009 LTP was released.
Once these base case models are developed, the AESO develops stressed cases as
required by Alberta Reliability Standards, to ensure the transmission system can meet future
load and generation under various conditions. The stressed cases are developed by varying
certain parameters:
n load conditions: winter peak, summer peak, summer light,
n generation scenario variation (e.g., north versus south gas),
n variable generation sources: maximum, zero, seasonal average,
n intertie flows: maximum export, maximum import, economy energy, zero,
n critical generators: on, off.
The transmission system is tested to ensure it can be reliably operated with the proposed
enhancements. If the assessment shows the system cannot be operated reliably, the AESO
identifies modifications to the projects to ensure that it can. The AESO also determines
if components of the various projects can be delayed or cancelled given the revised load
and generation forecasts.
PagE 46
AESO Long-term Transmission Plan
3.0 AESO Planning Process
Once the AESO has developed recommended enhancements for the 10-year planning
horizon, these enhancements are tested against alternate scenarios to determine if the
proposed bulk transmission system has the ability to meet different futures.
As mentioned earlier in Section 2.4, three alternate scenarios considering differing generation
futures were assessed for the LTP:
n gS1 – greenest: advances in clean energy solutions such as clean coal and wind.
n gS4 – High cogeneration: larger amounts of cogeneration in the northeast than
expected in the baseline scenario.
n gS5 – Business as usual: assumes existing coal plants will continue to operate
longer and prolonged uncertainty on climate change policy; further details are
described in Appendix E.
In addition to testing the transmission system’s ability to meet the scenarios in Table 4-4,
Appendix E, the AESO also tests the system’s ability to meet future loads and generation
under other unanticipated conditions such as major generator projects not proceeding as
planned or load – specifically in the northeast – being higher than forecast.
The sensitivity analysis was conducted for the bulk system (240 kV and above) for the year
2020. Three new cases were created from the 2020 summer peak case. Generator merit
order dispatch for GS1, GS4 and GS5 was developed and the transmission system was
stress tested with critical generators assumed offline.
The baseline generation scenarios propose specific large generation projects to be added
to the AIES by 2020. Some of these projects could have a significant impact on the LTP and
ultimately the system if they do not proceed. This analysis tested the impact on the system
of these generation projects not being developed as proposed. These included 375 MW
of generation in the Northwest region, 350 MW in the South region and 340 MW in the
Northeast region.
Load development in the Northeast region is uncertain. If load increases faster or slower
than expected, this could have an impact on supply into the region. For this analysis, loads
in the Northeast region were gradually increased from expected 2020 levels to determine
the point at which the system can no longer be operated reliably.
The proposed bulk transmission system is also assessed for the 20-year horizon. This
assessment is not required to comply with Alberta Reliability Standards and does not
have the same rigor as the 10-year assessment. For the post-2020 period a more generic
approach is undertaken with a focus on analyzing power flows across the major bulk system
cutplanes. The system is stress tested to determine its continued ability to meet expected
load growth. This evaluation is intended to determine the parts of the bulk transmission
system that might need further enhancement beyond 10 years. This approach is considered
adequate given the uncertainty around loads and generation beyond the first 10 years.
PagE 47
AESO Long-term Transmission Plan
3.6 ADDitioNAl Key CoNsiDerAtioNs
The following section provides insight into a number of additional key considerations that
must be taken into account when establishing a comprehensive transmission plan. These
elements, both wires and non-wires, serve to reinforce the planning, construction and
operation of a safe, reliable and secure transmission grid, one that directly supports a
fair, efficient and openly competitive market. Each of these sections is further discussed
in the attached appendices.
3.6.1 interties
Alberta continues to be one of the least interconnected jurisdictions in North America. Since
2002, Alberta has been a net importer. In 2010, compared to 2009, there was a nine per cent
increase in imports and a 10 per cent decrease in exports. This increasing import utilization
trend is expected to continue.
Transmission analysis and planning work continues in order to evaluate current and future
interregional transfer requirements to support both market and reliability objectives. Interties
are an essential part of a competitive market and provide support for reliability objectives.
3.0 AESO Planning Process
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PagE 48
AESO Long-term Transmission Plan
While no additional interties are identified prior to 2020 in the LTP, the AESO continues
to work on four main pillars of intertie work including: (1) restoring the existing interties to
their rated capacity as required by the T-Reg, (2) developing market rules and products
to support a sustainable intertie framework, (3) transmission analysis to evaluate where,
what size and when future interties may be required, and (4) defining and implementing
the processes and planning required to interconnect pending and future merchant interties.
The latter work is driven by a request to connect the Montana-Alberta Tie Line (MATL).
The assessment of interties is complex from technical, utilization and multi-jurisdictional
perspectives. Significant time is required to evaluate need, technology options, size, location
and costs and manage the multi-jurisdictional process required to permit such facilities. The
AESO intends to further assess and refine the costs and role of interties for both Alberta and
interconnecting jurisdictions and will initiate discussions with entities in other jurisdictions to
evaluate the size and scope and determine the mutual benefits of interties. The generation
outlook will impact this analysis as interties support a more intermittent fleet and larger scale
plant. Intertie projects initiated from other jurisdictions connecting to Alberta may influence
the timing of this evaluation as well.
The AESO will start to evaluate the impact of future possible southern interties as this
direction seems to suggest the most likely location for such expansion. For the post-2020
period our planners will evaluate the need and impact of a possible additional 1,000 MW
of intertie capacity by 2029.
Appendix F provides greater detail into the role, status and future of Alberta interties.
3.0 AESO Planning Process
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PagE 49
AESO Long-term Transmission Plan
3.6.2 transmission technologies
As part of the transmission analysis and planning process, the AESO evaluates technology
choices for new lines. Recently, the focus of these discussions has been on high voltage
direct current (HVDC) lines for the proposed Edmonton to Calgary 500 kV CTI project
and consideration of an underground portion of transmission in the Edmonton area.
Unlike many jurisdictions in North America, Alberta continues to depend on a series of
240 kV backbone lines underpinned with older 69 kV and 138 kV grid connections. The
prudent technological response to current growth and reliability concerns is to move to
a higher capacity and more efficient higher voltage 500 kV system backbone. This also
allows for the retirement of older and more inefficient 69 kV lines where possible. The most
advantageous infrastructure mix will be a combination of alternating current (AC) and direct
current (DC) transmission lines.
HVDC lines are commonly used in many jurisdictions to provide large-scale interconnections
in a system or between generation and load regions. 500 kV DC technology supports the
transport of large amounts of power over long distances more efficiently than traditional
AC transmission lines. HVDC allows for more efficient use of rights-of-way, utilizes a
smaller land footprint, reduces line losses, adds operational flexibility and provides for
more efficient system overall. Additionally, DC lines offer the benefit of scalability. The
AESO has incorporated this feature into the LTP by initially providing for two 1,000 MW
lines with the ability to scale up to 2,000 MW as demand grows, without having to alter the
lines themselves. By comparison, two 500 kV HVDC lines rated at 2,000 MW each have the
equivalent capacity of approximately 10 single circuit 240 kV AC lines.
Another important advancement in transmission technology is the use of high voltage
underground transmission cables. These cables have proven application in congested urban
areas such as Calgary and Edmonton using high voltage systems up to and including 240 kV.
The proposed addition of 500 kV underground systems is a relatively new application and
must be approved appropriately recognizing the greater cost implications. In response to
public requests, the AESO commissioned a study on the technical feasibility and lifecycle
costs associated with burying a portion (10 to 20 km of the proposed 500 kV double circuit
line of the Heartland project). The results of the study released by the AESO in February 2010
indicated burying some portion of the line is technically feasible subject to further testing and
validation for cold weather environmental conditions. In North America, there are no existing
500 kV underground cable systems of similar length that operate under extreme winter
weather conditions similar to Alberta. The AESO recognizes there are incremental costs for
underground alternatives and will continue to monitor the development of underground cable
technology and consider its application in Alberta based on technical feasibility and cost.
3.0 AESO Planning Process
PagE 50
AESO Long-term Transmission Plan
The technology considerations intrinsic to the effective design and operation of a robust grid
are incomplete without consideration of the sophisticated telecommunications infrastructure
that overlays the entire system. The current focus on enhancing existing system controls
as well as the monitoring, protection and reporting functions means that the role, application
and comprehensive planning of telecommunications infrastructure will need to be linked
to the physical transmission being proposed. The AESO has completed a comprehensive
evaluation of the existing telecommunication infrastructure and established a plan for growth.
The advent and deployment of fibre optic technology with its virtually unlimited bandwidth,
increased reliability and superior availability has resulted in most North American utilities
including fibre optics as the preferred solution for communications systems. Microwave
digital equipment currently used as the backbone of telecommunication system for
the transmission network in Alberta has a typical life expectancy of seven to 15 years.
Fibre optic cable generally has a similar depreciation as a steel tower transmission line
at 30 to 40 years. A typical standard 24-pair fibre optic cable is physically equivalent to
the characteristics of an overhead shield wire. Actual industry practice distributes services
across several pairs of fibre to mitigate the risk of losing total communications in the event
of damage to one fibre pair.
A more detailed discussion on transmission technologies can be found in Appendix G.
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3.6.3 environmental considerations
Environmental considerations are part of the LTP in two ways. First, the current and expected
environmental policy directly influences the need for transmission by either supporting or
discouraging the use of certain generation fuel sources. Second, environmental policies impact
the location and type of electrical load that may develop and the related transmission need.
The AESO also considers environmental impact in choosing general transmission study areas
and the technology to be employed. The assessment of environmental impact is specifically
included as part of project NID filings which are evaluated in a hearing process in front of the
AUC. The siting of final routes for CTI projects incorporates environmental considerations
through the Facility Application process.
In all cases, transmission projects are evaluated after taking environmental impacts, among
other factors, into consideration.
3.6.4 Aeso system operations
The AESO system controller function operates much like an air traffic controller, using
sophisticated data capture and analysis tools to monitor, analyze and direct the safe and
reliable operation of the AIES 24 hours a day, seven days a week. This is accomplished
using control systems that provide real-time visibility of power grid conditions and allow
for contingency analysis in the event of transmission system element failures.
In addition to balancing supply and demand in real time, the system controller is responsible
for all outage coordination, short-term and long-term operational planning, and working
collaboratively with transmission facility owners and Emergency Management Alberta
on system restoration activities to ensure that in the event of a major disruption to service,
normal operations can be quickly restored with minimal disruption to all Albertans.
Over the last decade, demands on the provincial transmission infrastructure have increased
significantly due to the growth in system load and the expansion of generating facilities –
facilities that are now more diverse in type and geographic location. The significant increase
of wind production in the south of the province and cogeneration in the north creates unique
operational challenges to the system. These types of generation facilities can be intermittent
in nature and operate in a manner that is not highly controllable: wind power is generated
when the wind blows and cogeneration facilities are designed and operated to meet industrial
process needs rather than power system requirements. The variability of generation
production has strained transmission operations over the past few years and will continue to
do so until the bulk and regional transmission systems are expanded to better accommodate
these types of generation sources.
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AESO operations manages the grid and system constraints through the effective execution
of documented policies and procedures to ensure consistency and effective implementation
of market rules. However, as the complexity and demand on the system increases, it has
become evident that additional information systems and technologies are needed to ensure
visibility and proactive mitigation of potential system overloads. The AESO began upgrading
its Energy Management System in 2007 with stage one implemented in 2009. These
upgrades will continue in phases over the next three to five years as the AESO integrates
this new technology into daily operations.
The new Energy Management System provides greater situational awareness and
contingency analysis options to system controllers and their support teams, allowing for
transmission capacity to be maximized while maintaining a safe and reliable operating
condition. Custom tools are being developed and implemented for the control room to
monitor and manage the variability of wind resources within the province, allowing for
the system to connect and absorb a greater volume of renewable resources than would
otherwise have been possible.
Effective operation of the grid directly supports Alberta’s fair, efficient and openly competitive
market structure. As the size and complexity of Alberta’s power system grows, AESO
operations will continue to evolve and employ the most appropriate technologies in its
drive to maintain a safe, reliable and efficient system.
3.6.5 Ancillary services
The LTP considers the non-wires, interim and supplemental operational support required
for the safe, reliable and efficient operation of the AIES and the fair, efficient, open and
competitive operation of the market. These considerations are in addition to existing physical
transmission plans. One of the critical considerations of a sustainable transmission plan is
the need to minimize the cost of ancillary services by removing system constraints. Having
said that, the AESO recognizes that as more variable wind resources are integrated into the
system, the need for ancillary services will increase. The AESO is continuing to assess this
requirement and will include the results of the analysis in future updates of the LTP.
With the current transmission system operating at or near its limit during peak conditions,
until new transmission is built the system is reliant on operational tools and non-wires
alternatives. For example, the system relies on transmission must-run (TMR) in the Rainbow
Lake, northwest Alberta and Calgary areas to maintain system reliability and serve local
loads that are isolated from the system. In addition, wind generation constraints occur in
the Southwest region due to delayed reinforcement of transmission in that area. Additionally,
several areas of Alberta experience generation or load constraints when transmission
facilities are taken out of service, whether for planned maintenance or forced outages
such as during lightening storms.
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When the system experiences constraints or operational disturbances, the AESO relies
on the procurement of ancillary services and the development and implementation of
operational procedure. The AESO also continues to rely on coordination of planned outages
to minimize supply adequacy issues. System controller training and procedures are
developed and implemented to support ongoing monitoring and response alternatives
to challenging system conditions.
Ancillary services used to support reliability include:
n transmission must-run service – supplied by a generator that is required to
be online and operating at specific levels in parts of the system where local
transmission capacity is insufficient to meet local demand.
n operating reserve – available output from a generator that can be dispatched, or
load that can be reduced, to maintain system reliability in the event of an imbalance
between supply and demand on the electricity system. Operating reserve is further
broken into regulating reserve and contingency reserve.
n regulating reserve – available output from a generator that can be dispatched,
and is responsive to automatic generation control, to provide the power needed to
address the lag period between balancing supply and demand (as generators catch
up to increasing or decreasing load) as well as for voltage support.
n contingency reserve – available output from a generator that can be dispatched, or
load that can be reduced, to restore the balance of supply and demand of electricity
following a contingency or unforeseen event on the system. Contingency reserve
is further broken into spinning (immediate generator response) and supplemental
(10-minute response – generation and load) reserve.
n Black start service – supplied by generators that are able to restart their generation
facility with no outside source of power. In the event of a system-wide blackout,
black start providers are called upon to re-energize the transmission system by
providing start-up power to generators who cannot self-start.
n load shed scheme service – supplied by electricity consumers (load) who have
agreed with the AESO to be automatically tripped off (curtailed) in order to instantly
reduce demand in the event of an unexpected problem that threatens the balance
of supply and demand of electricity on the system.
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In accordance with the Transmission Regulation, load customers pay for the costs of ancillary
services, including operating reserve. The mechanism the AESO uses to recover these costs
from load customers is the tariff, which is filed for approval with the AUC. In the AESO tariff,
costs for ancillary services are identified in the rate component applicable to load customers
and broken out in the following charges:
n The operating reserve charge recovers costs associated with regulating, spinning
and supplemental reserve (both active and standby) and with some miscellaneous
ancillary services where the cost varies with pool price.
n The voltage control charge recovers costs associated with the provision of
transmission must-run services.
n The other system support services charge recovers costs associated with some
miscellaneous ancillary services where the cost does not vary with pool price.
The operating reserve charge makes up the largest part of ancillary services costs recovered.
The transmission must-run expense is the next largest expense and the other system support
services charges represent the smallest charge.
The procurement and use of ancillary services will continue to be critical to ensuring the
physical transmission system remains safe, reliable and able to respond to customer
connection needs. By planning transmission infrastructure appropriately, the reliance on
and need to procure large volumes of ancillary services will diminish over time. These
services supplement the available capacity and operational protocols that are part
of effectively operating the grid 24 hours a day, seven days a week. A more detailed
discussion on ancillary services can be found in Appendix H.
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3.6.6 market evolution
As described throughout this LTP, Alberta’s electricity market provides choice to consumers
and incents generators to build in Alberta and to import power into Alberta when needed by
the transmission system. Transmission is required to serve both consumers and generators
in the delivery of electricity and also to connect new and varying fuel types of generators
wherever they decide to locate. Simply put, transmission development addresses both
reliability and market objectives. As noted in Alberta government policy and confirmed
by the T-Reg, an uncongested transmission system is critical to ensuring an effective
and efficient electricity market for all.
As it is an iterative process – loads drive generation, which in turn drives transmission,
which supports all customers – the market must continue to evolve to meet the needs of the
system. This current LTP is based on assumptions that generation will be unencumbered
allowing investment opportunities in new generation facilities. It is also based on
assumptions related to market rules for various fuel types such as support for wind
development and a framework for interties. Accordingly, the AESO continues to support
market evolution to encourage generation and load development in the province.
The LTP relies on the market, working in consultation with the AESO, to address key design
practices including:
n Integration of wind resources – procurement of new ancillary services products
and rules for forecasting wind and power management.
n Creation of ancillary products to restore the capability of current interties to rated
capacities and address system reliability.
n Development of demand participation products that, with smart grid technologies,
may lead to efficiencies in demand requirements.
n Development of framework details for participation of interties in the Alberta market
including tariff design, capacity allocation rules and design to consider integration
of future interties including possible merchant lines.
n Implementation of congestion management rules and procedures for
short-term constraints.
Each of these priorities is consistent with baseline assumptions built into the LTP and
supports an evolving competitive market for electricity while responding to a growing
economy. Appendix I provides more detail on the market evolution in Alberta.
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3.6.7 transmission Constraints management (tCm)
The transmission system must be free of transmission constraints for the underlying market
model to function effectively. Transmission constraints can interfere with the flow of electricity
from one part of the system to another or alter the normal dispatch of the energy market
merit order, restricting market participants’ access to the market and impacting market
prices. Transmission policy must ensure transmission access and contribute to a stable
investment climate in order to maintain investor confidence.
Alberta’s transmission system is currently running at capacity, which requires the AESO to
actively manage constraints on transmission lines across the province. Until transmission
upgrades are in service, the AESO will continue to take appropriate operational action to
maintain system reliability, optimize the use of existing transmission and manage constraints.
The T-Reg provides for adequate transmission so that, on an annual basis, and at least
95 per cent of the time, transmission of all anticipated in-merit energy can occur when
operating under abnormal operating conditions.
Reliability criteria are applied in planning studies to identify potential constraints and within
system monitoring and control systems to provide warnings of real time potential or actual
constraints. AESO monitoring and control systems detect constraints that the system
controller must mitigate using established protocols and procedures.
The T-Reg requires the AESO to make rules and establish practices to manage transmission
constraints that may arise from time to time. The AESO has been consulting on constraints
management with industry since the T-Reg became law in 2004. During those discussions,
the AESO has been guided by the principles and recommendations of both the 2004
Transmission Development Policy (TDP) and the 2005 Electricity Policy Framework.
The AESO has recently received confirmation from the AUC of Transmission Constraints
Management Rule 9.4 (TCM Rule), a generic rule that will serve as a template for managing
all transmission constraints, planned or unplanned. The TCM Rule is aligned with the TDP
which requires the AESO to use reverse merit order and pro-rata curtailment to manage
constraints. The TCM Rule also results in a minimal amount of price impact or distortion
as mandated by the TDP. The TCM Rule incorporates procedures intended to minimize
the impact of constraints on the energy market by curtailing ancillary services before
energy and prevents constraints of longer duration from impacting market participants’
offer behaviour.
The TCM Rule will also guide the AESO’s development of Operating Policies and Procedures
(OPPs). OPPs provide the system controller predetermined policies and procedures to apply
in real time to address specific known constraints. These known constraints may have been
identified in the planning stages of system development or in the nearer term operational
environment when applying reliability criteria to the system as it exists at the time or as it will
change in the very near term. Although guided by and aligned with the generic TCM Rule,
the appropriate procedure required for a known constraint must be determined on a case-
by-case basis and, when it becomes part of an OPP, is subject to stakeholder consultation.
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The AESO notes that transmission constraints impact the market supply and demand
balance and the approved TCM protocol is expected to work effectively within the current
market design to restore that balance while having a minimal impact on pool price.
The AESO currently manages, and will continue to manage congestion effectively by using
practices and procedures such as the connection process, regional operating procedures
and remedial action schemes. These measures optimize the use of the system and lead to
less frequent and shorter duration congestion events. The AESO operates the system in
a manner that ensures reliability criteria and reliability standards are met. The AESO notes
that the amount of future regional congestion will grow and increase the generator and load
restrictions associated with meeting the reliability criteria until planned regional transmission
upgrades are in place. Until transmission upgrades are complete, the AESO expects
congestion will be infrequent and of short duration using the proposed TCM Rules.
The AESO will continue to develop and implement Independent System Operator (ISO) Rules
and operational procedures to manage constraints that have been identified in the planning
stages of system development and operations. The ISO rules will be consulted on through
the established rule consultation process as prescribed by the AUC. The transmission
facilities required to alleviate constraints will be identified through the AESO’s connection
process and the long-term planning process.
The AESO regularly monitors the impact of transmission constraints on the market and
undertakes annual stakeholder reviews to discuss regional constraint issues. Please refer
to the AESO’s 24-Month Reliability Outlook (Appendix B) for historical constraint information
on our website.
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3.6.7.1 Impact of transmission constraints on the wholesale electricity market
Alberta’s wholesale market design utilizes a single clearing price for all power regardless
of the location from which power is delivered. To support this design, transmission must be
available to all supply and load customers in a non-discriminatory manner and with sufficient
capacity to ensure neither load nor generation is constrained. This is necessary to eliminate
geographical pricing advantages caused by transmission congestion and exposes every
generator to full competition from every other generator in the system. This encourages all
generators to offer close to their marginal cost of production in order to increase their chance
of being dispatched ahead of their competitors. In turn, this provides consumers the lowest
delivered cost of power. The full benefits of the competitive wholesale market can, therefore,
only be realized with an unconstrained transmission system.
However, the transmission system is currently constrained. In areas of mild to moderate
constraint on the transmission system, the full output of lower priced generators cannot
reach consumers, which results in the dispatch of higher priced generators to meet demand,
thereby raising the overall price of power. In areas of significant constraint, such as in
northwest Alberta, the AESO must contract for the right to use local generation to meet
local demand because insufficient transmission capacity is available to meet local demand.
The use of generators in this manner is referred to as transmission must-run (TMR) service
and often results in the dispatch of more expensive generators to meet demand than would
be the case if sufficient transmission capacity was available.
The cost of constrained generation can be significant, particularly when sufficient amounts
of low price generation is unable to be used to meet demand, and higher priced generation
is used instead. This results in a higher price of power to consumers. Figure 3.6.7-1
demonstrates how a small transmission constraint of 100 MW of supply could result
in a significant increase in the market price.
$/M
Wh
Actual merit order Merit order with a 100 MW constraint
8,00
0
8,10
0
8,20
0
8,30
0
8,40
0
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0
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0
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0
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00
10,1
00
10,2
00
$1,000
$900
$800
$700
$600
$500
$400
$300
$200
$100
$0
Figure 3.6.7-1: Example of the impact constrained generation has on price
Original price at 9,500 MW dispatch level: $73.35/MWh
Increased price at 9,500 MW dispatch level (with 100 MW constraint applied): $494.70/MWh
Difference:$421.35/MWh
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The use of TMR services also comes at an incremental cost to the system. In 2010 the actual
cost for TMR was $26.1 million.
The impact of constrained generation on pool price varies with the offer curve, demand levels
and other market fundamentals. It is estimated that for constraints similar to those observed
in the past three years, pool prices are, on average, greater by $1.59/MWh for regular
constraints and $8.02/MWh for constraints associated with major events compared to
an unconstrained system.
In addition, over the past three years, the cost of TMR has averaged $0.58/MWh due
to location specific constraints. These costs, the observed trend of increasing levels of
constraint, and the currently forecasted increases in demand and generation levels indicate
that there is significant value to incremental transmission capacity in Alberta. Alberta’s single
price energy-only market design is predicated on an unconstrained transmission system.
3.6.8 telecommunications
The AIES utility telecommunications networks owned and operated by transmission facility
owners are used for the transmission of teleprotection signals, operational data, SCADA
data, and voice and mobile radio communications.
Section 10 of the T-Reg requires the AESO to prepare a long-term plan for the transmission
system. The definitions included in the EUA imply that telecommunications system planning
is included in the LTP.
The operation of the transmission system requires a functional and effective
telecommunications network where the design and performance of the communications
system will contribute to the ability of the system to meet Alberta Reliability Standards.
As part of the LTP, the telecommunications plan provides a blueprint for how Alberta’s
aging microwave telecommunication systems will be replaced and/or modified with more
advanced and durable fibre optic technology. It should be noted that in certain areas of the
province, the microwave system will continue to be used as it is more cost effective. Also
of note is that each transmission project allows for between three to five per cent of the total
cost for telecom upgrades specific to the project. No additional capital cost is anticipated
to be incurred to implement this plan over the next decade. The general principles of the
telecommunication plan are as follows:
n Operate the network with extremely high reliability.
n Support ongoing system growth including applications for smart grid in the future.
n Meet standards for low latency (for teleprotection) and high standards for
network security.
n Minimize environmental impact.
n Meet total operational cost objectives.
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The major projects summarized in the Table 3.6.8-1 below represent the additional
telecommunication projects required to support this LTP. Further details of the
telecommunications plan are found in Appendix J.
table 3.6.8-1: major telecommunication network developments
region/area Project comments
Edmonton Keephills – Sundance – Optical ground wire (OPGW) installation to meet Genesee – Ellerslie – latency requirements for protection system Summerside
North Calder – Poundmaker AESO to review specifications and include OPGW between 37S North Calder and Poundmaker
red deer 17S Benalto – 63S Red Deer Inclusion of OPGW on rebuild of the 138 kV lines to close gap between east and west HVDC lines
Multichannel service Study and plan required to improve to Bighorn network reliability
calgary Foothills reinforcement (FATD) OPGW to be considered for rebuild of several 240 kV lines
74S Janet – 102S Langdon Inclusion of OPGW on new 240 kV line
ENMAX SS65 – 74S Janet OPGW on rebuilt 911L will tie into existing ENMAX fibre ring
camrose Camrose – Strome Evaluation required for OPGW between east HVDC and Hanna area transmission redevelopment
B.c. intertie Coleman – Natal OPGW to provide redundancy and meet NERC and ARS standards for BC Hydro interconnection
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4.1 oVerView
The Long-term Transmission Plan (filed June 2012) – also referred to as the LTP or the Plan –
provides an updated summary of the key inputs used in transmission analysis, describes the
process and steps involved in completing the evaluations, defines the essential planning criteria
to be addressed, and culminates in a summary of recommended transmission projects required
to meet system need. This section describes in detail the actual key inputs, the analysis
performed and the resulting recommendations of the Plan.
4.2 loAD foreCAst – fUtUre DemAND AND eNergy oUtlooK (2009-2029)
4.2.1 overview
Over the last few years, domestic and global economic outlooks have changed substantially
with many jurisdictions encountering significant growth slowdowns. However, Alberta’s
economic fundamentals have generally remained positive. While the slowdown that started
in 2008 was significant, economic stimulus packages in 2009 around the world improved
the economic outlook and crude oil prices have made a dramatic recovery. The injection
of capital into troubled banks and the financial sector improved access to capital and
companies began to increase their capital budgets and drilling activity.
Toward the end of 2009 and into the first half of 2010, the outlook for major projects,
including oilsands projects, began to improve. This was aided by higher crude oil prices
combined with lower labour costs, low interest rates, declining cost of construction materials
and the introduction of new technologies.
In the past nine years (2001-2010) Alberta Internal Load (AIL) peak demand has grown by
an average of 255 megawatts (MW) or 2.9 per cent per year from 7,934 MW to 10,236 MW,
an overall increase of 28.9 per cent. Electricity consumption has grown from 54,467 gigawatt
hours (GWh) in 2001 to 71,723 GWh in 2010 for an overall increase of 32 per cent.
This recent trend in growth is expected to continue over the forecast period with peak
demand growth forecast to be 3.3 per cent each year on average. Consumption
is expected to grow 3.2 per cent each year on average during the same time period.
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4.2.2 summary of key inputs
The key factor driving the Alberta economy continues to be investment in the development of
oilsands, which is largely driven by oil demand and world oil prices. This investment creates
jobs and economic activity that, in general, will lead to increases in annual electricity use.
The key inputs to the load forecast are Alberta Gross Domestic Product (GDP), population
growth, oilsands production and upgrading production as presented in Table 4.2.2-1.
table 4.2.2-1: key forecast inputs
oilsands upgrading alberta gdP Population production production year (2011 $ millions) (000s) (million bbls/d) (million bbls/d)
2010 $285,461 3,745 1.5 0.7
2015 $352,226 4,076 2.2 0.9
2020 $396,373 4,375 2.9 1.0
The AESO monitors and reflects any updates to this information to ensure plans remains
current and relevant.
The load forecast is dependent upon the long-run outlook for development and economic
growth in Alberta. Economic growth, as measured by GDP, has historically been correlated
with electricity consumption in the province, as shown in Figure 4.2.2-1. As such, GDP
is a key input assumption to the Future Demand and Energy Outlook (2009-2029) (FC2009).
The AESO uses The Conference Board of Canada’s long-run provincial forecasts as a basis
for this input.
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The AESO routinely validates the key inputs to its load forecast by comparing and
interpreting the differences between varied third party providers of economic input
assumptions. Figure 4.2.2-2 below illustrates and compares the 2011 and 2012 Alberta
GDP forecasts from a number of economic data providers.
9,000
8,500
8,000
7,500
7,000
6,500
6,000
5,500
5,000
320,000
300,000
280,000
260,000
240,000
220,000
200,000
Ave
rage
hou
rly A
lber
ta In
tern
al L
oad
(MW
)
Alb
erta
GD
P (2
011
$ m
illio
ns)
Average Alberta Internal Load (MW) Alberta GDP (2011 $ millions)
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Figure 4.2.2-1: Alberta GDP and demand growth
6%
5%
4%
3%
2%
1%
0%
Ann
ual r
eal G
DP
gro
wth
2011 2012
AverageConferenceBoard (usedin FC2009)
RBCEconomics
CIBCScotiabankConferenceBoard
(current)
BMOCapitalMarkets
EDCAssociates
TDEconomics
Alberta Finance and Enterprise
ERCBLaurentianBank
Figure 4.2.2-2: Selection of 2011 and 2012 real GDP growth forecasts from various sources
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Another key input to the FC2009 is population growth. In the FC2009, it was assumed
that strong economic growth resulting from oilsands development would create jobs that
incent immigration. The latest population forecasts confirm that assumption as shown by
Figure 4.2.2-3. Strong population growth is still expected and has been confirmed by third
party forecasts.
4,600
4,400
4,200
4,000
3,800
3,600
3,400
3,200
3,000
Pop
ulat
ion
(000
s)
HistoricalConference Board (used in FC2009)Conference Board 2010 Forecast
IHS Global Insights (January 2011 Forecast)Alberta 2011 Budget Assumption
Figure 4.2.2-3: Alberta population forecasts
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
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13,000
12,000
11,000
10,000
9,000
8,000
7,000
6,000
Ave
rage
hou
rly A
lber
ta In
tern
al L
oad
(MW
)
FC2009 FC2008 FC2007Historical
Figure 4.2.2-4: Historical comparison of load forecasts from 2007, 2008 and 2009
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
4.0 AESO Analysis and Planning Results
Another comparison used to validate and test the accuracy of the AESO’s energy forecasting
models is to track actual average load compared to past AESO forecasts. Figure 4.2.2-4
above compares historical average hourly AIL over the past 10 years to the forecast (FC2009)
and previous forecasts (FC2007 and FC2008) going out to 2020. The 2008/2009 recession
caused a delay in load growth, but as seen in Figure 4.2.2-4, 2010 shows a recovery, putting
the forecast back on track.
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4.2.3 Anticipated trends
As stated earlier, the key factor driving the Alberta economy continues to be growth in the
oilsands sector. This growth will continue to increase load in the Northeast region, as well
as in other areas of the province that supply this economic driver with materials, labour
and associated infrastructure such as pipelines to move the product to market.
Alberta oilsands producers are continuing to develop oilsands leases using existing and
new technologies. The trend toward higher electricity intensity compared to historical
values is caused by moving into more difficult reservoir zones which require additional
electrical pumps and other associated on-site loads. This is highlighted by the desire
to improve steam-to-oil ratios and reduce greenhouse gas (GHG) emissions.
The industrial (without oilsands) sector has shown a drop in year-over-year energy growth
from 2006 to 2009. This drop was attributed to a decline at chemicals, forestry and gas
processing sites throughout the province. 2010 actuals show growth over 2009 in all these
sectors and this growth trend is expected to continue with new pipelines and pipeline
expansions, as well as growth from other industrial sites in the province.
Residential usage per capita is expected to continue to follow the historical trend of positive
growth. Consumers’ abilities to afford larger homes, use additional appliances and
electronics more than offsets historical energy efficiencies.
7%
6%
5%
4%
3%
2%
1%
0%
–1%
–2%
–3%
–4%
GD
P g
row
th
FC2009 GDP Assumption
Conference Board Winter 2011 Update
Conference Board 2010 AssumptionIHS Global Insights (January 2011)
Alberta 2011 Budget Assumption
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Source: The Conference Board of Canada, IHS Global Insights, Alberta Finance and Enterprise
Figure 4.2.3-1: Forecasts of real GDP growth in Alberta
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Figure 4.2.3-1 shows assumed GDP growth used in the FC2009 for 2009 through 2020
compared to a number of updated forecasts. As Figure 4.2.3-1 shows, FC2009 assumes
very strong growth in 2011 and 2012 compared to other forecasts. The AESO assessed the
validity of this strong growth when it was creating the FC2009. At the time, it was deemed
reasonable as that strong short-term growth was based upon an aggressive, but rapid,
economic recovery followed by more modest growth.
The AESO believes the long-term GDP growth assumption used in the FC2009 is reasonable.
While strong growth is forecast for 2011 and 2012, it can also be seen in Figure 4.2.3-1 that
the GDP growth assumed by the FC2009 in 2014 and 2015 is well below other, more recent
third party forecasts. This means that more recent GDP forecast updates expect that growth
is still going to occur but later than was expected in the FC2009.
The actual risk of delayed growth is minimal because the FC2009 attempts to capture
long-run trends, not short-term fluctuations. The FC2009 assumed annual GDP growth
of 3.2 per cent from 2010 to 2029. This forecast is in line with The Conference Board of
Canada’s 2010 provincial long-run economic forecast of 3.3 per cent, as well as IHS Global
Insight’s January 2011 forecast of 3.0 per cent over the same timeframe. Figure 4.2.4-1
shows the AESO’s forecast inputs are consistent with publicly available industry data.
4.2.4 Uncertainties and concerns looking forward
The FC2009 recognizes future uncertainty in regards to timing, size and number of large
oilsands extraction facilities and upgraders in the northeast of the province. This uncertainty
is reflected in the FC2009 demand which shows a drop in demand from the AESO’s
FC2007 in the first 10-year period. In particular, the Northeast region shows a decrease
of approximately 1,000 MW by 2020 from the FC2007. However, a significant 60 per cent
increase in load is still expected by 2020. In general, the results of the FC2009 show a delay
of approximately one to two years in AIL peak demand by 2020/21.
The AESO continuously monitors regional forecasts against current projects in the connection
queue to test the long-term forecast against current project conditions. If oilsands developers
can address workforce challenges, develop expansions in modules to address project
delays and incorporate new technology and improvements, the Northeast region load
forecast could be understated by approximately 450 MW by 2015 and 370 MW by 2020.
The AESO serves load in the Fort Nelson area of B.C. This load is included in the AESO
forecast based on information provided by BC Hydro. There is uncertainty regarding the
rate of possible load development in this area, specifically related to future development of
the Horn River Shale Basin, as well as potential development of a future transmission line
connecting Fort Nelson to BC Hydro’s grid.
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Future load considerations the AESO has noted are changing trends in demand response,
conservation and energy efficiency, as well as environmental costs. Future policy changes
may have an impact on Alberta’s energy producing sectors including how they use natural
gas and electricity to meet their environmental requirements. The AESO will continue to study
and monitor the development of distributed generation offsetting grid load as well as how
electricity is used in a variety of residential, commercial, industrial and oilsands sites.
Additional information on load can be found in Appendix D.
The key FC2009 assumptions of GDP growth, oilsands production growth and population
growth all remain in line, or are lower than the latest forecast updates. Therefore, the AESO
believes that the key input assumptions used in the FC2009 remain valid, and the FC2009
remains appropriate for long-term transmission planning.
Bars represent the range of uploaded third party forecast for each input.
3.4%
3.3%
3.2%
3.1%
3.0%
2.9%
2.8%
Fore
cast
ann
ual a
vera
ge g
row
th r
ate
FC2009 assumption Range of updated forecasts for each input
GDP growth
6.9%
6.8%
6.7%
6.6%
6.5%
Fore
cast
ann
ual a
vera
ge g
row
th r
ate
Oilsandsproduction growth
1.7%
1.6%
1.5%
1.4%
1.3%
Fore
cast
ann
ual a
vera
ge g
row
th r
ate
Population growth
Figure 4.2.4-1: Comparison of inputs used for GDP growth, population growth,and oilsands production growth and latest updates
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4.3 geNerAtioN foreCAst
To provide an outlook for the future transmission system required in Alberta, information
about the size, location and type of future generation that may develop in the province is
required. Generation development is a competitive business, which makes forecasting the
timing and location of new generation challenging. To address this challenge, the AESO
continually evaluates generation project development as well as expected changes to the
drivers and costs of the development of various generation technologies. To ensure the
transmission system is adequately planned to provide reliable power to Albertans and to
facilitate the competitive electricity market, the AESO created a baseline forecast and a
corresponding range of generation scenarios against which the transmission system is
tested to identify where system reinforcement could be required to meet future need.
A number of key changes since filing of the 2009 LTP have shaped the updated assessment
of future generation. The most significant factors include:
n An expectation of future climate change policy that leads to a reduced greenhouse
gas cost of approximately $30/tonne in 2020.
n The federal government announcement related to coal emission standards being
fixed at natural gas emission levels.
n The federal government announcement that speaks to coal-fired generation
retirements occurring at the later of 45 years (facility end of life) or expiration
of Power Purchase Arrangements (PPAs).
n Expectations of healthy natural gas supplies and stable long-term gas prices.
n The expiration of the federal subsidy program for renewable power generation
and no current indication of a provincial subsidy being employed or its impact
on future wind generation opportunities.
n The potential for increased development of cogeneration facilities in the Northeast
region of Alberta.
n Recent industry announcements associated with new generation facility requests
and the closure of existing generation facilities.
Development of additional generation in Alberta will be driven by growth in demand as
well as the need for capacity to replace retired units. The reduction in generation capacity
due to plant retirements, in combination with the consumption forecast by the AESO in
the FC2009, means that approximately 6,000 MW of new effective generation is expected to
be developed by 2020, with 5,000 MW to meet load growth and 1,000 MW to replace retiring
capacity. Effective capacity accounts for derates to intermittent resources such as wind and
is less than installed capacity. By 2029, nearly 13,000 MW of effective additions are expected
to be added in Alberta, approximately 8,700 MW to meet load growth and 4,300 MW to
replace retiring capacity (see Figure 4.3-1).
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25,000
20,000
15,000
10,000
5,000
0
MW
Figure 4.3-1: Alberta forecast of effective generation capacity requirements
2010
/201
1 20
11/2
012
2012
/201
3 20
13/2
014
2014
/201
5 20
15/2
016
2016
/201
7 20
17/2
018
2018
/201
9 20
19/2
020
2020
/202
1 20
21/2
022
2022
/202
3 20
23/2
024
2024
/202
5 20
25/2
026
2026
/202
7 20
27/2
028
2028
/202
9 20
29/2
030
Existing coal Existing gas Existing effective hydro
Effective existing wind Effective existing other Forecast peak demand (AIL) Expected effective generation capacity
By 2020, total effective generation capacity is expected to grow from 11,901 MW to
approximately 17,000 MW. While Alberta’s supply is currently weighted toward thermal
coal-fired generation, this is expected to change given the aforementioned factors coupled
with the following key principles:
n Natural gas-fired generation is anticipated to supply the growth gap to 2020.
n Coal retirement at 45 years or end of PPAs, per the federal government
policy statement.
n Current provincial price on carbon of $15/tonne till 2014, expected to increase
post 2014.
n Amount of new wind generation still uncertain; future carbon value unknown today.
n Peaking capacity will depend on the scale and timing of wind build out.
n Cogeneration growth will continue largely as a function of oilsands growth.
n Locational diversity of future gas generation still to be tested.
n Future generation mix will largely depend on market and/or policy evolution.
n The transmission infrastructure contemplated in this LTP will facilitate development
of an efficient and diverse generation mix.
n By 2020, total installed generation capacity is forecast to grow to 19,000 MW.
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4.3.1 gas-fired generation
Gas-fired generation is currently an attractive option due to the expectation of stable natural
gas prices in the future, relatively lower GHG risk, and proven technologies with competitive
capital costs that can be developed in less than five years.
For new baseload capacity, combined cycle natural gas generation is attractive from the
perspective of cost (natural gas, capital cost) and certainty of technology and its ability
to meet GHG criteria. In addition, locating gas-fired generation is more flexible than with
other fuel types. Project proponents are developing a number of sites in southern and
northern Alberta. Brownfield coal sites are also attractive locations for combined cycle
developments as they have existing infrastructure, available water, existing permits,
a skilled workforce, transmission access and an accepting community.
Alberta’s expanding industrial sector’s increased need for steam and heat makes highly
efficient, low-cost cogeneration an option for future growth. Additional gas-fired peaking
capacity is attractive for maintaining system balance and integrating variable generation
into the system.
44% Coal 5,782 MW
41% Gas 5,371 MW
7% Hydro 879 MW
6% Wind 777 MW
2% Other 203 MW
Current installed capacity
29% Coal 5,588 MW
50% Gas 9,634 MW
5% Hydro 981 MW
13% Wind 2,500 MW
2% Other 395 MW
Figure 4.3-2: Generation mix: current and 2020 baseline
2020
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4.3.2 Coal
The proposed regulation on coal plant emission standards would make coal-fired generation
prohibitively expensive for new additions post 2015. Beyond the Keephills 3 plant, no new
conventional coal plants are expected in Alberta in the baseline generation scenario. Instead,
gas-fired generation is expected to be developed as discussed previously. This is a major
difference from the 2009 LTP, which considered several conventional coal resources to
be viable generation options for development prior to 2020.
Prior to 2020, a modest amount of new coal capacity will be added to Alberta’s system
with the connection of Keephills 3, a supercritical pulverized coal plant currently under
construction and slated for commissioning in 2011. The plant has potential for carbon
capture and storage in 2015. These developments, coupled with the potential for upgrades
at existing plants and the possibility of a demonstration combined cycle unit fired by syngas
created through underground coal gasification, support this view. Beyond 2020 it is expected
that clean coal technologies will become commercially available as a result of extensive
research and development funding worldwide. This will create an option for developing
Alberta’s abundant coal resource.
4.3.3 wind
Wind resources remain strong in Alberta; however, there is uncertainty about the economics
of wind generation and future revenue from green attributes. As of the first quarter of 2011,
indications are that up to 1,600 MW of wind projects have received power plant approvals
from the Alberta Utilities Commission (AUC), have applications before the AUC, or have
purchased turbines. Forecasting longer-term wind development required an assessment of
the economics of wind development including green attributes and future market prices.
Overall, the result is a baseline forecast of wind capacity reaching a total installed capacity
of 2,500 MW in Alberta by 2020. The forecast strikes a balance between the Provincial
Energy Strategy’s direction to support the development of green energy (specifically wind)
and recognition of the uncertainty surrounding the economics of wind generation in Alberta
and the attractiveness of locating development in other jurisdictions.
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O fi
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4.3.4 other renewable projects and new technologies
There are numerous biomass, small hydro and waste heat projects proposed for the
province. Policies and grants (i.e., Alberta bio-energy grants) to promote these types of
developments are likely to continue and be available in the future, helping the development
of smaller (100 MW or less) renewable projects.
Additionally, various generation technologies such as batteries, solar, flywheels, small nuclear
and geothermal are developing. For the most part, the pace at which these technologies
become commercial and economic is dependent on future climate change policy and overall
development of the electricity industry. Any game-changing technologies are expected to
come about post 2020.
4.3.5 large projects
Large hydro and nuclear developments have previously been proposed by developers in
Alberta. However, the development (regulatory, financing, design and construction) process
for these projects is likely to take over a decade. These types of developments are
considered in the 2020-2029 portion of the generation forecast.
4.3.6 baseline generation scenarios
Table 4.3.6-1 provides the detailed additions by type included in the baseline generation
scenarios used to develop the LTP. Prior to 2020, the majority of generation additions are
expected to come from gas-fired generation, combined cycle, cogeneration and simple
cycle, and wind. These baseline generation scenarios were validated through market
simulations to ensure the mix of generation adequately meets load and market signals
that would support the development of the generation mix.
With a large portion of future capacity being gas-fired, which is more flexible than other types
of generation in terms of location, two scenarios are considered. The first scenario locates
the majority of the gas-fired combined cycle and simple cycle additions in northern Alberta
only (includes all other Alberta generation assumptions) and the second scenario locates
them primarily in southern Alberta. The northern baseline scenario sees 73 per cent of the
combined cycle capacity and 55 per cent of the simple cycle additions located in the north.
The southern baseline scenario sees all the combined cycle and 55 per cent of the simple
cycle additions located in the south.
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Post 2020, it is expected that the economics of generation will evolve due to the impact
of climate change policy and the costs of GHG and technology development. Overall this
may shift the emphasis from gas-fired additions to clean coal technology and long lead-time
projects like hydro and nuclear, which are included in the baseline generation scenario near the
end of the 2020 decade. Climate change policy and related funding and research could lead
to the development and commercialization of new technologies. The technologies that prove
to be the front runners in North America and Alberta are still to be determined; however,
700 MW capacity was included in the baseline scenarios post-2020 to account for these new
technologies. Currently these new technologies are expected to be geothermal, small nuclear,
biomass, commercial combined heat and power, solar and other distributed types of generation.
The post 2020 baseline shows two options in Figure 4.3.6-1. Both have a similar increase in
generation capacity but outline different potential for location and fuel type, which is useful
in analyzing the impact on the system. The first baseline (coal renaissance) considers the
addition of substantial clean coal capacity of 970 MW. The second baseline (nuclear develops)
considers the alternative case of 1,000 MW of nuclear generation in the province. Both
baselines include a potential for 1,500 MW of hydro development.
The AESO also considers how the transmission system would need to develop should
alternative generation patterns develop. A number of uncertainties could have an impact
on the types of generation that will develop in Alberta’s market. These include future
environmental policies and their corresponding costs and subsidies as well as the pace
of technology development for the new generation options. From a generation capacity
perspective, three additional scenarios were created to evaluate what transmission may
be required in the future. The scenarios are briefly described here and additional information
can be found in Appendix E.
Figure 4.3.6-1: 2029 Baseline scenario generation mix
55% Gas 13,832 MW
18% Wind 4,500 MW
14% Coal 3,424 MW
10% Hydro 2,481 MW
4% Other 1,095 MW
2029: Coal renaissance
53% Gas 13,539 MW
18% Wind 4,500 MW
11% Coal 2,724 MW
10% Hydro 2,481 MW
4% Other 1,095 MW
4% Nuclear 1,000 MW
2029: Nuclear develops
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table 4.3.6-1: Baseline generation scenario development: 2010-2020 and 2021-2029
2020 2029
coal nuclear Baseline renaissance develops
Forecast Alberta winter peak demand (FC 2009) 15,162 18,695 18,695
10 per cent effective reserve margin 1,516 1,870 1,870
Effective generation capacity required to meet peak demand and reserve margin
16,678 20,565 20,565
Existing generation capacity as of mid 2010 12,745 12,745 12,745
Effective existing generation capacity as of mid 2010 11,901 11,901 11,901
Retirements to 2020 1,136 1,136 1,136
Retirements from 2021 to 2029 – 3,134 3,134
Net effective generating capacity after retirements 10,765 7,631 7,631
Total effective generating capacity required 5,913 12,934 12,934
additions by fuel type to 2020 2021 to 2029
Coal 834 970 270
Cogen 1,687 865 865
Combined cycle 1,935 2,730 2,397
Simple cycle 779 603 643
Hydro 100 1,500 1,500
Nuclear 1,000
Other 290 700 700
Wind 1,864 2,000 2,000
Total additions from 2010 to 2020 7,489 7,489 7,489
Total effective additions 2010 to 2020 5,948 5,948 5,948
Total additions from 2021 to 2029 9,368 9,375
Total effective additions 2021 to 2029 7,018 7,025
Total effective generation capacity 16,713 20,597 20,604
Total installed capacity 19,098 25,332 25,339
4.0 AESO Analysis and Planning Results
The first generation scenario is a case where climate change policy moves forward faster
than forecast in the baseline generation assumptions. In this case, clean coal develops faster
as a result of aggressive funding and research across North America and the world. There
will also be additional coal retirements due to GHG cost impacts on project economics.
Conversely, GHG costs provide support for the development for more wind generation
beyond the amount assumed in the baseline generation scenario.
In the second generation scenario, government policy provides stronger incentives for the
development of cogeneration in the oilsands industry. In this scenario, an additional 850 MW
of cogeneration is developed in the oilsands industry, fulfilling baseload requirements and
replacing combined cycle in the baseline generation scenarios.
The third generation scenario considers a case where climate change policy moves forward
at a slower rate than in the baseline generation scenario impacting the current and future
generation mix. This would impact all current generation technologies.
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AESO Long-term Transmission Plan
4.4 bUlK trANsmissioN system iNClUDiNg Cti
4.4.1 overview
The AESO plans Alberta’s transmission system by evaluating requirements within various
geographic regions in the province and the bulk system that interconnects these regions.
The bulk transmission system is the integrated system of transmission lines and substations
that delivers electric power from major generating facilities to load centres. The bulk system
also delivers power to, and receives power from, neighbouring jurisdictions. The bulk
transmission system generally includes the 500 kilovolt (kV) and 240 kV transmission lines
and substations.
The bulk transmission system is essential to overall system reliability, forming the backbone
that delivers bulk power to load centres, connects new and existing generation and enables
import and export transactions with neighbouring jurisdictions.
The AESO’s technical analysis examines and identifies the required reinforcements of the
bulk transmission system, aligning which facilities are required in a specific timeframe to
meet forecast generation and load requirements and planning scenarios, and to facilitate
the attainment of the objectives in the Provincial Energy Strategy.
The bulk system is studied by defining transmission cutplanes. These cutplanes combine
the loading on groups of transmission lines that connect two regions within the bulk system.
The four major cutplanes used to study the bulk transmission system in Alberta are:
1. Edmonton to northeast transmission path (nE cutplane) – There are currently
two 240 kV lines between Edmonton and the northeast area. These two lines, plus
a number of 138 kV lines, interconnect the Edmonton area with the northeast area
and are referred to as the Northeast (NE) cutplane.
2. Edmonton to northwest transmission path (nW cutplane) – There are currently
three 240 kV lines between the Wabamun Lake area and the northwest area. These
three lines, plus a number of 138 kV lines, interconnect the Wabamun Lake area
with the northwest area and are referred to as the Northwest (NW) cutplane.
3. Edmonton to calgary transmission path (Sok cutplane) – There are currently
six 240 kV transmission lines between Edmonton and the Red Deer area. These
six lines, plus a number of 138 kV lines, carry all the power from northern Alberta,
south from the generating plants in the Wabamun Lake area (Keephills, Genesee,
and Sundance) to central and southern Alberta and are referred to collectively
as the South of Keephills-Ellerslie-Genesee (SOK) cutplane.
4. South to calgary transmission path (South cutplane) – There are currently three
240 kV lines between the south area and the Calgary area. These lines, plus a
number of 138 kV lines, interconnect the south area with the Calgary areas and
are referred to as the South cutplane. In addition, the South cutplane includes
the 500 kV line from B.C. to Calgary.
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1. Northeast
2. Northwest
3. SOK
4. South
SUBSTATIONS
Existing transmission lines
240 kV
500 kV
Bulk cutplanes
Figure 4.4.1-1: Existing bulk transmission system and cutplanes
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Besides the four cutplanes internal to Alberta, there are two interties to other jurisdictions
that are considered part of the bulk system:
alberta to B.c. transmission path – There are currently one 500 kV and two 138 kV lines
between Alberta and B.C. These three transmission lines collectively constitute the intertie
to B.C. Through this intertie, Alberta is connected to the B.C. system and on through to the
transmission systems in the U.S. Pacific Northwest and the rest of the systems comprising
the Western Interconnection of North America.
alberta to Saskatchewan transmission path – Synchronous operation with Saskatchewan is
not possible as it is part of the Eastern Interconnection of North America and Alberta is part
of the Western Interconnection. These two large interconnected systems are joined together
via high voltage direct current (HVDC) back-to-back (i.e., asynchronous) links at various
points in Canada and the U.S. (refer to Figure 1 in Appendix G for a map showing the
Eastern and Western Interconnections). The Alberta-Saskatchewan intertie comprises an
asynchronous link, known as the McNeill converter station, located near Empress, Alberta.
The converter station is connected via a 138 kV transmission line to the Alberta system and
a 230 kV line to Swift Current, Saskatchewan. This intertie provides Alberta access to the
electricity markets in the Eastern Interconnection through Saskatchewan and Manitoba
and the U.S. Midwest and similarly provides entities in these jurisdictions with access to
the Alberta market.
The main facilities of the existing bulk transmission system and the associated cutplanes
are shown in Figure 4.4.1-1. As the figure shows, the bulk system connects the major
load/generation centres of Fort McMurray, Edmonton and Calgary, as well as other regions
of Alberta.
4.4.2 transmission technology alternatives
There are a number of possible technological choices that could be considered to meet the
long-term development requirements for Alberta’s transmission system. The system can
be reinforced using transmission lines designed for alternating current (AC) operation with
voltages ranging from 240 to 765 kV. A HVDC option with transmission lines designed for
operation at voltages ranging from ±250 kV to ±500 kV is also possible.
Alberta currently uses 240 kV and 500 kV AC for its bulk transmission system and it is
anticipated that facilities at these voltage levels, along with the planned 500 kV HVDC
lines, will provide the appropriate balance between capacity and cost in the Alberta context.
A significant portion of the bulk transmission systems in the western half of North America
uses the same voltage levels and for these reasons, these voltage levels are considered
appropriate for future transmission development in Alberta. However, HVDC transmission
is recognized as providing the required power transfer capacity with a lower overall land-use
impact, it provides the ability to directly control both power flow quantity and direction,
and is consistent with government policy. For these reasons, HVDC has been selected as the
preferred technology choice for those situations where these attributes are seen as significant
advantages for the long-term development of the bulk transmission system in Alberta.
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4.4.3 Project status
4.4.3.1 Edmonton to Calgary transmission system reinforcement
The existing transmission system that delivers power from the Edmonton region to the South
region relies on six 240 kV transmission lines in the Edmonton to Red Deer area and seven
240 kV lines between Red Deer and Calgary. Lower voltage lines (138 kV and 69 kV) also
contribute to the aggregate capacity but the majority of the capacity is provided by 240 kV
lines. The system connecting these two regions has not been upgraded since the early
1990s. Load growth in southern and central Alberta is stressing the existing system
such that capacity will fall short of reliability requirements by 2014. Currently, when one
of the existing six lines is removed from the grid for maintenance or due to forced outages,
system congestion occurs.
Reinforcement of the transmission system between the Edmonton and Calgary regions
is needed to avoid reliability issues for consumers in south and central Alberta, improve
the efficiency of the transmission system, restore the capacity of existing interties, and
avoid congestion that prevents the market from achieving a fully competitive outcome.
Transmission constraints and congestion also slow development of new competitive
generation in the Edmonton area and further north.
Meeting the long-term capacity requirement for the Edmonton to Calgary component of
the bulk system using high-capacity HVDC transmission lines makes most efficient use
of rights-of-way and minimizes land-use impacts.
While a number of factors and conditions are considered in making this technology choice,
including consultation, economics and efficiency, a priority is given to minimizing land-use
impacts in support of government policy presented in the Provincial Energy Strategy, which
suggests the use of HVDC technology where possible.
Two HVDC high-capacity lines are planned to be in service by 2014. Analysis indicates the
preferred orientation of these lines is for one line on the west/central portion of the province
connecting the existing Wabamun Lake/Edmonton hub to the Calgary area hub. The preferred
orientation of the second line is on the eastern side of the province, connecting the Heartland
hub northeast of Edmonton to a southern hub near West Brooks. Each line will initially be
designed for 1,000 MW capacity with provision for expansion to 2,000 MW in future. The
AESO has determined the future expansion will likely be needed beyond 2020.
Construction of both lines substantially increases the usable capacity of the first line. The
first line alone cannot be fully utilized without the second line being in service as the loss
of the first line would create too large a contingency on the system. Construction of these
lines removes uncertainty and sends a clear and positive signal to consumers, generation
and intertie developers that unrestricted access to transmission capacity will be in place to
deliver future generation to the market and reliably meet the electricity needs of consumers
in central and southern Alberta.
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The two new HVDC lines will strengthen the transmission system between Edmonton
and Calgary such that it will be sufficient to meet the needs of this corridor for over 10 years,
before future capacity upgrades are required as outlined previously. The right-of-way
requirements for the two lines are substantially less than all other AC technology alternatives.
More gradual additions of single circuit AC lines would result in up to 10 additional
transmission lines to achieve the same capacity, more than doubling the right-of-way
requirement of the HVDC lines.
The estimated cost of each of the HVDC lines considered in the LTP, including converter
stations, is approximately 50 to 90 per cent higher than a double circuit 500 kV AC line.
The two high-capacity lines will remove uncertainty for generation and intertie developers.
Alberta’s transmission system will be capable of providing efficient and unrestricted access
for many years, thereby facilitating investment decisions by generation developers.
The lines also facilitate access between renewable generation zones and the market to
transport large quantities of electricity when the wind is blowing or when high river flows
occur at hydro plants.
Adding a higher capacity transmission line reduces how often the system must operate
near its limit, thereby reducing line losses. Improving system efficiency saves money and
is environmentally beneficial as it reduces greenhouse gases and other emissions created
during the production of wasted energy.
Currently, interim technical measures have been required to allow connection of new
generation. These measures are used as a last resort until the transmission system can
be reinforced. All forms of generation in the north will be constrained to some degree until
the needed transmission facilities are in place. Transmission reinforcement takes longer to
implement than generation projects, and must be developed well in advance of specific
generation projects.
Based on analysis of the generation scenarios described earlier, the AESO has determined
that proceeding with the development of both lines with in-service dates of 2014 is prudent.
In addition, development of both lines at this time takes advantage of the current market
conditions for procuring materials and synergies that can be achieved in engineering,
procurement and construction.
Implementing high-capacity alternatives exposes the system to situations where a large loss
of capacity can occur; however, adding both circuits at the same time permits each line to
back up the other and minimizes exposure to service interruptions. The transmission facility
owners (TFOs) of the two HVDC lines have filed their facility applications with the AUC to
support the in-service dates.
The AESO will continue to monitor generation development in the province. Should there
be a major difference between the assumed generation scenarios and actual development,
the AESO will review all assumptions, adjust its plans accordingly, and reassess its project
development strategy.
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42 Hanna
29 Hinton / Edson
34 Abraham Lake
44 Seebee
56 Vegreville
40 Wabamun
30 Drayton Valley
48 Empress
38 Caroline
47 Brooks
31 Wetaskiwin
32 Wainwright
35 Red Deer
49 Stavely
37
Provost
13 Lloydminster
43 Sheerness
46 High River
39 Didsbury
6
Calgary
60
Edmonton33 Fort Sask.
45 Strathmore
/ Blackie
36 Alliance / Battle River
57 Airdrie
Figure 4.4.3.1-1: Edmonton-calgary transmission system reinforcement
Edmonton-calgary transmission system reinforcementn 2014 ISDn Two 500 kV HVDC lines (1,000 MW each)
– West-Genesee to Langdon– East-Heartland to Brooks
n Expandable to 2,000 MW eachn Required to:
– Address reliability issues– Improve efficiency– Accommodate long-term growth– Support energy market
n Included in 2009 LTP as CTI
The lines also facilitate access between renewable energy zones and the market to transport large quantities of electricity when the wind is blowing or when high river flows occur at hydro plants.
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4.4.3.2 Heartland transmission system reinforcement
The oilsands industry is expected to continue to grow and is the primary driver of the need
for new electricity infrastructure development in the northeastern part of Alberta, followed
by growth in pipelines and associated pumping loads. There are two main components of
load associated with extracting and processing bitumen. The first component includes
facilities used to extract bitumen from the oilsands. This can be in the form of a mining-type
operation that extracts the oilsands from its original location and moves it to a processing
facility where bitumen is separated from sand. It can also be in the form of in situ recovery
of bitumen directly out of the oilsands formation. In Alberta, most of this activity is located
in the Fort McMurray, Cold Lake and Peace River areas.
The second component of oilsands load is the demand for power associated with upgrading
bitumen into synthetic crude oil in a refinery-type facility. These facilities can either be located
close to bitumen extraction sites (e.g., Fort McMurray area) or in another area with bitumen
piped to the facility (e.g., Fort Saskatchewan/Heartland area).
The existing transmission system into the Northeast region and Heartland area is constrained.
The northeast is currently supplied by a double circuit 240 kV line from Edmonton through
Fort Saskatchewan, and a single circuit 240 kV line from Wabamun to the Fort McMurray area.
Reinforcement of the transmission system between Edmonton and the Heartland is required
to avoid system reliability issues in both the Heartland area and the Fort McMurray area.
Currently, interim technical measures in the form of operating procedures are required to
ensure reliable supply to the northeast. Continued constraints and congestion will slow
oilsands and bitumen upgrading development in Alberta. Adding high capacity 500 kV lines
into the area will facilitate investment decisions by oilsands developers. These decisions not
only relate to potential load growth in the area, but can also facilitate increased cogeneration
opportunities by allowing excess electric generation at these sites to connect to the
transmission system, providing new generation sources for the Alberta grid.
The proposed 500 kV double circuit line from the existing Ellerslie substation in south
Edmonton to a new substation in the industrial Heartland area will strengthen the transmission
into the area and will provide a strong source for an eventual 500 kV line into the Northeast
region. This transmission enhancement not only reinforces the system between Edmonton
and the northeast but also provides a termination point for the proposed east HVDC line.
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60 Edmonton
27 Athabasca / Lac La Biche
40 Wabamun
31 Wetaskiwin
30 Drayton Valley
33 Fort Saskatchewan
Figure 4.4.3.2-1: Heartland transmission system reinforcement
Heartland 500 kvn 2013 ISDn Double circuit 500 kV from Ellerslien Required to:
– Supply northeast load– Interconnect east HVDC– Supply Heartland load
n Identified in 2009 LTP as CTI
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19 Peace River
29 Hinton / Edson
28 Cold Lake
26 Swan Hills
56 Vegreville
Athabasca / Lac La Biche
40 Wabamun
23 Valleyview
24 Fox Creek
13 Lloydminster
21 High Prairie
60 Edmonton
Fort McMurray
Figure 4.4.3.3-1: Fort mcmurray transmission system reinforcements
East 500 kv Fort mcmurrayn 2021-2022 ISDn Connects 500 kV from Heartlandn Required for northeast loadn Identified in 2009 LTP as CTI
West 500 kv Fort mcmurrayn 2017 ISDn Two stages
1. Thickwood-Livock operated at 240 kV2. Genesee-Livock 500 kV and conversion
of Thickwood-Livock to 500 kVn Required for northeast loadn Identified in 2009 LTP as CTI
East 500 kv Fort mcmurray
West 500 kv Fort mcmurray
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4.4.3.3 Fort McMurray transmission system reinforcements
As with the transmission reinforcements required into the Heartland area, transmission
reinforcement into the Fort McMurray area is driven by oilsands development.
The Fort McMurray area is unique from a planning perspective as it has a significant number
of large industrial customers. These customers will be contracting both demand transmission
service (DTS) and supply transmission service (STS) with varying degrees of usage to supply
process requirements and for electric supply reliability. Planning for a transmission system
that is capable of handling the full range of all contracted DTS and STS will result in large
capital investments. On the other hand, not planning for the full range of DTS and STS can
result in congestion and possible violation of the AESO’s reliability criteria. The solution is
to find the most likely maximum load and supply scenarios that the Fort McMurray region
will experience during the next 10 years and plan accordingly, taking into account any
necessary revisions.
The specific facilities recommended for this reinforcement are a 500 kV AC line from the
Genesee generating station to a new 500 kV substation in the Fort McMurray area (Stage 1)
and a 500 kV AC line from the new Heartland substation to the new Fort McMurray 500 kV
substation (Stage 2). The AESO validates the configuration of these lines as described in
the Electric Utilities Act as follows:
Stage 1a: A transmission line from a new substation to be built in the Thickwood Hills,
approximately 25 kilometres (km) west of the Fort McMurray Urban Service Area, to a
substation at or in the vicinity of the existing Brintnell 876S substation. This segment will
be initially energized to 240 kV and be interconnected with a substation near Brintnell.
Upon completion of Stage 1B, the entire line (Stage 1A and 1B) will be energized to 500 kV.
Stage 1B: A transmission line at or in the vicinity of the existing Brintnell 876S substation
to a substation in the vicinity of the existing Keephills-Genesee generating units.
Stage 2: A transmission line located east of the facilities described in Stage 1 and
geographically separated from those facilities for the purposes of ensuring reliability
of the transmission system, from a new substation to be built in the Gibbons-Redwater
region, to a new substation to be built in the Thickwood Hills area, approximately
25 km west of the Fort McMurray Urban Service Area.
Based on analysis of the load and generation scenarios, the AESO has determined that
Stage 1 of the Fort McMurray line should be in operation in 2017. The in-service date
of Stage 2 is determined to be sometime after 2020.
The AESO has been continually monitoring load growth and generation development
in the area based on review of connection requests received, information received from
transmission and distribution facility owners, various industry announcements and from
direct consultation with oilsands developers. The AESO reviews and assesses this information
and determines if any adjustments are required to project in-service dates should business
conditions associated with loads and generation change.
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4.4.3.4 Southern Alberta Transmission Reinforcement (SATR)
The South region is currently Alberta’s primary wind power generation area. As of April 30,
2011, the AESO has received requests for connection of nearly 6,700 MW of wind power,
of which over 5,000 MW is located in the South region. The AESO connections queue and
project list are updated monthly to reflect the progress of projects. For the most recent
queue, visit the AESO website at www.aeso.ca and follow the pathway customer
connections > connection Queue. These numbers are considerably lower than the
forecast used in the 2009 LTP. It is expected that not all wind generation that has requested
connection to the system will be constructed, and there is uncertainty about where the
projects will ultimately be located.
Regardless of the location of future wind turbines, there is currently insufficient capability
in the South region transmission system to meet the needs of the existing and proposed
generation. Given existing system constraints, the South region transmission system
will require substantial improvements, including multiple new 240 kV transmission
system loops and substations and upgrading of existing facilities to accommodate
the generation connections.
The AESO received approval from the AUC
for the SATR Needs Identification Document
(NID) in 2009. This project is flexible enough
to accommodate various amounts of future
wind development to a cumulative capacity
of 2,700 MW. The project includes three
stages of development, the first two stages
consisting of various 240 kV lines, and a
240 kV system loop connection to the
500 kV Langdon-Cranbrook line. The third
stage is a 240 kV line between Ware
Junction and Langdon.
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The AESO tested the approved SATR project to determine its current and future adequacy
by applying transmission reliability criteria and using the latest load forecasts and generation
assumptions. The AESO’s preferred alternative for the reinforcement considered various
factors required by the Transmission Regulation. Given the revised wind generation scenario,
the third stage between Ware Junction and Langdon is not required until the latter part of this
decade. The AESO will continue to monitor the load growth and generation development in
the area and update the need date as necessary.
At the direction of the AUC, the AESO, with stakeholder consultation, established milestones
that need to be met before each component of the SATR project progresses to construction.
In addition to meeting the projected needs of wind generation development and load growth,
the third stage of the project could be reconfigured by connecting it to the south terminal
of the second Edmonton to Calgary 500 kV HVDC line near Brooks as a way to enhance
the efficiency of the HVDC systems and create the flexibility to deliver additional wind
energy into the grid.
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4 Medicine Hat
55 Glenwood
52 Vauxhall
47 Brooks
53 Fort MacLeod
49 Stavely
43 Sheerness
46 High River
6 Calgary
45 Strathmore /
Blackie
54 Lethbridge
Figure 4.4.3.4-1: Bulk – Southern alberta transmission reinforcement
Southern alberta transmission reinforcementn 2011-2017 ISDn Extensive 240 kV looped system
and tie to 500 kV linen Required to integrate renewable
and gas-fired generationn NID approved
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4.4.3.5 Foothills Area Transmission Development (FATD)
In addition to the 240 kV looped system in the south, the FATD project is an integral part
of the system required to move wind energy to the load centres of the Foothills and greater
Calgary area. This project includes a 240/138 kV substation near High River and two double
circuit 240 kV lines from Foothills into Calgary, one to the east side of the city and the other
to the west side. The project is planned to be developed in stages between 2014 and 2017.
In addition to integrating wind energy, the Foothills area development provides other benefits
by creating a system that will accommodate potential gas-fired generation in and near the
City of Calgary, as well as mitigating local transmission constraints within the city to facilitate
future load growth.
Generation development, both wind in the south and gas-fired generation in and around
Calgary, can impact the FATD project. Depending on where and how quickly these forms of
generation develop, the west leg from Foothills substation to Sarcee substation may need
to be advanced. The Foothills area NIDs are being developed and are expected to be filed
with the AUC later this year.
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46
High
River
6 Calgary
45 Strathmore
Cochrane
Okotoks
Figure 4.4.3.5-1: Bulk – Foothills area transmission development (Fatd)
Foothills area transmission development (Fatd)n 2014-2017 ISDn 240/138 kV substation south of Calgaryn 240 kV lines east and west into Calgaryn Other 240 kV enhancementsn Required for reliability, load and to integrate
renewable and gas-fired generationn NID under development
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4.4.3.6 South Calgary transmission system reinforcements
The City of Calgary peak load is expected to reach approximately 2,000 MW by 2020. Based
on information from the City of Calgary’s land use planning department, the south part of the
city in particular is expected to continue to grow. The construction of a new South Health
Campus in the southeast sector indicates an increasing population in the south area
specifically. In addition, the South Health Campus requires a geographically separate
redundant electric supply to ensure a reliable supply of electricity.
The transmission system into the south part of the City of Calgary requires reinforcement.
Currently, there are three 138 kV circuits supplying south Calgary and if one of these circuits
is out of service for maintenance, a subsequent outage would result in the requirement for
planned outages to keep the remaining 138 kV circuit from overloading.
The proposed development to supply south Calgary includes a new 240/138 kV substation
near the intersection of 88 Street SE and Highway 22X and associated 138 kV and 240 kV
lines to interconnect into the existing system. The anticipated in-service date for this
development is 2012.
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6 Calgary
Cochrane
Airdrie
Figure 4.4.3.6-1: cti South calgary source
calgary local area enhancementsn 2012 ISDn 240/138 kV substation in south Calgary
and 138 kV enhancementsn Required for load and reliabilityn Included in the 2009 LTP as CTI
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4.4.3.7 Northwest transmission system reinforcements
The Northwest region imports power from the rest of the AIES because peak load in the
region is greater than generating capacity. The region imports about 55 to 60 per cent of
its annual energy supply and this means the region is dependent on its interconnections
to supply its load. The transmission system in the region is currently weak and relies on
generation units located in the region to provide voltage support and reliability, particularly
in the far northwest corner of the area. The need to operate this generation indicates that
the transmission system is not adequate to reliably serve the current load.
The Northwest region is primarily a load area and relies heavily on power transfers from the
Wabamun Lake area and, under certain conditions, from the northeast. As a result, a major
transmission outage between Wabamun Lake and the Northwest region could cause a
phenomenon called voltage collapse, which could cause a sustained outage.
To mitigate the potential voltage collapse, the AESO is proposing two new projects. The first
is a double circuit 240 kV line from Bickerdike (near Edson) to Little Smoky. The second is
a re-termination of the east end of the Brintnell to Wesley Creek 240 kV line from Brintnell
to Livock to tie to the west Fort McMurray 500 kV line at or near Livock.
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29 Hinton / Edson
20 Grande Prairie
26 Swan Hills 27 Athabasca / Lac La Biche
40 Wabamun
23 Valleyview
24 Fox Creek
21 High Prairie
60 Edmonton
33 Fort Sask.
Figure 4.4.3.7-1: Bulk – northwest projects
re-terminate 9l15 at new 500 kv substation
240 kv bulk reinforcement into nW
re-terminate 9l15 at new 500 kv substationn 2017 ISDn Re-terminate Brintnell end of
Brintnell-Wesley Creek 240 kV linen Required to mitigate voltage
collapse and overloads in northwestn New project
240 kv bulk reinforcement into nWn 2015 ISDn 240 kV double circuit line from Bickerdiken Required to mitigate voltage collapse
and overloadsn New project
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4.4.4 bulk projects cost estimates and timelines
The bulk projects are at various stages of completion with some having filed NIDs and some
NIDs approved by the AUC, while others are still at the conceptual stage. The CTI projects
are included in the bulk system infrastructure.
These projects are listed in Table 4.4.4-1 along with a brief description and the estimated
ISD. The transmission capability increases provided by these developments are assumed
to have been achieved when assessing the future needs on the bulk transmission system.
The AESO is committed to working with industry to develop milestones for designated CTI
projects and to advance this work in a timely fashion. The milestones will provide indications
of when to proceed with further staging of these project expansions. Currently the focus
will be on providing milestones for the future capacity upgrades for the two HVDC lines
(from 1,000 MW to 2,000 MW) and for each of the legs of the Fort McMurray CTI project.
table 4.4.4-1: Bulk transmission system projects
cost estimate year in service Project description Bulk region (2011 $ millions)
2012 South Calgary 240/138 kV substation in south Calgary South $37 source (CTI) and related 138 kV transmission lines
2013 Heartland Double circuit 500 kV line from Ellerslie to a new Northeast $537 500 kV (CTI) 500/240 kV substation near Fort Saskatchewan
2014 West HVDC (CTI) HVDC 500 kV line connecting the Wabamun area Edmonton – $1,329 near Genesee with the Calgary area at Langdon Calgary
2014 East HVDC (CTI) HVDC 500 kV line connecting the Northeast area Edmonton – $1,622 at Heartland with the South area near Brooks Calgary
2015 Bickerdike – Double circuit 240 kV line from Northwest $205 Little Smoky Bickerdike to Little Smoky
2017 West Fort McMurray 500 kV AC line connecting Wabamun area near Northeast $1,649 500 kV (CTI) Genesee to the Northeast area near Fort McMurray
2017 9L15 Re-terminate the east end of the Brintnell-Wesley Northwest $40 Re-termination Creek 240 kV line from Brintnell to Livock
2011-2017 South area Multiple 240 kV double circuit lines from South $2,287 transmission and within the south to the Calgary area reinforcement
2014-2017 Foothills area 240/138 kV Foothills substation near High River, South $711 transmission two double circuit 240 kV lines from Foothills development to east and west Calgary, and several local 240 kV and 138 kV enhancements
total $8,417
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4.4.5 Unique considerations and uncertainties on the bulk system
In order to capture uncertainty that could impact the bulk system transmission requirements
in the future, additional scenarios and sensitivities to the baseline assumptions are considered.
These allow for the evaluation of typically larger scale generation trends that may occur and
directly impact future need requirements. To that end, the AESO also developed three
alternate generation scenarios referred to as:
n GS1 – Greenest
n GS4 – High cogeneration
n GS5 – Continuation of coal generation
These scenarios change the type, location and amount of generation in various areas
of the province and will have different impacts on power flows through the system.
The AESO examined the impacts of these scenarios on the timing of the recommended
transmission upgrades:
GS1 – Greenest scenario
GS1 is the greenest scenario and is distinguished by 1,500 MW of additional wind energy
in the South and Central regions (1,020 MW and 480 MW respectively).
The recommended system enhancements were included in the study cases with the
exception of Stage 3 of the South Area Transmission Reinforcement, which is a double
circuit 240 kV line from Ware Junction to Langdon. Stage 3 is not required for the baseline
generation assumption of 2,500 MW of wind by 2020.
Results show additional reinforcement will be required under GS1. The most significant issue
is apparent voltage instability for several 240 kV outages in the South as well as outages in
the Central region. Overloads also occur under certain conditions; however, these tend to be
localized issues. The AESO will continually monitor wind development in Alberta and recommend
additional local reinforcement if and when it appears more wind than forecast will develop.
GS4 – High cogeneration scenario
GS4 is the high cogeneration scenario that sees the addition of about 850 MW of
cogeneration in the Fort McMurray area.
The recommended enhancements modelled in the study case included the west
Fort McMurray 500 kV line but not the east Fort McMurray 500 kV line as it has currently
been assessed with an in-service date of 2021-2022.
Results indicate the bulk system as planned can easily accommodate the change in flows
resulting from the addition of cogeneration in the Fort McMurray area. Local regional overloads
may occur due to some specific generation locations. The AESO will continually monitor the
generation development and may recommend local reinforcement as needed.
GS5 – Continuation of coal generation scenario
GS5 assumes current coal technology will continue. The main difference between GS5
and the baseline scenarios is the replacement of the Swan Hills coal gasification plant with
combined cycle generation. Combined cycle plants like Swan Hills are in the northern part
of the province and the impact on flows on the transmission system is small.
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Study results indicate there are overloads on two 240 kV circuits in the Wabamun Lake –
Edmonton area for common tower failures between Wabamun Lake area and Edmonton,
and within Edmonton. This would suggest that for GS5, further strengthening of the
system between Wabamun and Edmonton will be required. This assumes the Swan Hills
generation facility is replaced in part by a combined cycle generator in the Wabamun area.
If the generation is located elsewhere in the province, it will change requirements for
transmission reinforcement.
In addition to the above generation scenarios, the following considerations have been
taken into account:
n As mentioned earlier, the Fort McMurray area is unique from a planning perspective
as it has a significant number of large industrial customers. These customers will
be contracting both demand transmission service (DTS) and supply transmission
service (STS) with varying degrees of usage to supply process requirements and
for electric supply reliability. Planning for a transmission system that is capable
of handling the full range of all contracted DTS and STS will result in large capital
investments. On the other hand, not planning for the full range of DTS and STS
can result in congestion and possible violation of the AESO’s reliability criteria.
The solution is to find the most likely maximum load and supply scenarios that
the Fort McMurray region will experience during the next 10 years.
n Each of the regions studied in the LTP have unique load and generation
characteristics. Changing certain primary assumptions could have an impact
on the timing of transmission reinforcements between the areas.
n The three regions where these assumptions could have the greatest impact are:
– northwest – the baseline generation scenario considered the addition of a
375 MW coal gasification combined cycle plant near Swan Hills and a development
at H.R. Milner by 2020. If these generation facilities do not proceed, the resulting
requirements for transmission into the northwest will be significantly impacted.
– northeast – in addition to the possibility of higher than anticipated cogeneration,
which is identified as Generation Scenario GS4 and examined as part of the
generation scenario sensitivity analysis, the possibility also exists for loads to
increase or cogeneration to be lower than proposed in the base scenario. Either
of these conditions could result in changes to in-service dates and the possibility
of requiring new projects for transmission reinforcement into the northeast.
– South – generation additions in the south include simple cycle and combined
cycle gas-fired facilities that total about 1,700 MW. If one or more of the major
facilities proposed for the south do not materialize, flows on the north-south
cutplane will be higher than anticipated. In addition to reduced generation in
the south, it is also possible that wind energy will increase more quickly than
anticipated. This uncertainty was examined in GS1, the greenest generation
scenario identified above. The HVDC system being planned has the required
design margin to accommodate such scenarios.
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sensitivities if generation projects do not proceed as anticipated
Swan Hills
The Swan Hills coal gasification project is anticipated to be in service in the 2018-2019
timeframe. Given that this is new technology, there is some uncertainty regarding the
timing of this facility.
Studies were run to test the system in 2020 without this facility. Results indicate the system
is sufficiently robust that if the Swan Hills facility is not in place in 2020, no further
enhancements will be required in that timeframe. This assumes the west 500 kV line
to Fort McMurray is in place and the 9L15 line is re-terminated at Livock.
Saddlebrook
In the north baseline generation scenario, Saddlebrook is anticipated to be online in 2015.
If the north scenario materializes and Saddlebrook does not proceed, north-south flows
will increase.
Results of the studies indicate the system is sufficiently robust should Saddlebrook not
proceed under the north generation scenario. The only problem seen in this scenario
is a localized 240 kV overload in Edmonton for a common tower failure. This assumes
that both HVDC 500 kV CTI lines are in place.
Northeast cogeneration
The baseline generation scenarios include 17 new cogeneration facilities that would
add 1,470 MW of generation in the Fort McMurray area. If approximately 25 per cent
of these projects do not materialize, it could impact flows into the northeast from the
Edmonton region.
The system was tested removing five of the proposed projects for a total reduction in
northeast generation of 340 MW. Results indicate the system as proposed is robust enough
to allow for increased flows into the northeast should 340 MW of cogeneration not materialize.
Northeast loads
For this analysis, loads in the northeast were gradually increased from the expected 2020
levels to determine the point at which the system could no longer be operated reliably.
Loads in the northeast were gradually increased to determine at what point the transfer
capability would be exceeded under contingency conditions (single outages and common
tower failures). The maximum increase was set at 830 MW or about 20 per cent of the
forecast 2020 load. The first constraint occurs at an increase of 170 MW and is an overload
on a 138 kV line in the Fort Saskatchewan area for a double circuit common tower outage.
Other constraints are seen at about 250 MW, 560 MW and 750 MW all on 138 kV circuits
with the last one being in the Athabasca area.
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The sensitivity analyses described previously show that the bulk system being planned
is robust enough to accommodate various uncertainties associated with load growth and
generation development. However, local regional reinforcement may be required based
on geographic location of the load and generators. The AESO will continue to monitor
the load growth and generation development and initiate system changes as required.
Should there be a major difference between the assumed generation scenarios and actual
development, the AESO will review all assumptions, adjust its plan accordingly and reassess
its project development strategy.
4.4.6 bulk transmission system post-2020
Determining the need for projects in the post-2020 period reflects and builds on the analysis
of the first 10-year horizon. The projects identified with in-service dates pre-2020 serve as
a starting point for the post-2020 period planning evaluation. A more generic approach is
undertaken with a focus on power flows across major bulk system cutplanes. The system is
stress tested to determine its continued ability to meet expected load growth on the Alberta
Interconnected Electric System beyond 2020.
As indicated in the previous section, a number of projects originally identified in the 2009 LTP
have had their in-service dates adjusted to the post-2020 period after a refreshed analysis
for this LTP:
table 4.4.6-1: Bulk system projects with iSds post 2020
Project in-service date
North Calgary 240 kV supply 2021
CTI: East Fort McMurray 500 kV 2021-2022
CTI: increase capacity of both 500 kV HVDC lines Post 2020
The post-2020 assessment was performed by incrementally increasing the flows between
regions and examining the limits of those flows under single contingencies and double
contingencies where two circuits are on the same towers. Typically, the analysis of these
two cases identifies the need for transmission enhancements.
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The assessment identifies the flow levels at which overloads or voltage stability issues begin
to occur. Outage simulations were conducted only on 240 kV and above facilities but facilities
at 138 kV and below were also monitored.
The following speaks to the specific conditions and impacts seen in this analysis:
Northwest region
The assessment was performed by increasing loads in the Northwest region and
correspondingly increasing generation in the Edmonton and South regions.
Results indicate that the overloads on 138 kV circuits into and within the Northwest region
are first seen when flow increases exceed about 80 MW. The number of overloaded 138 kV
elements increases rapidly once flows are increased beyond about 140 MW. The load in
the Northwest region is expected to increase at about 40 MW per year, which means system
enhancements may be required within the 2022-2023 timeframe. This will depend on
generation additions in the Northwest region that might offset load increases.
Northeast region
The assessment was performed by increasing the loads in the Northeast region and
correspondingly increasing generation in the Edmonton and South regions. This is the same
assessment that was performed for the sensitivity study discussed in Section 4.4.5,
Northeast Loads.
The first overload on the local area 138 kV system shows in Fort Saskatchewan when flows
into the Northeast region are increased by 180 MW. Subsequent overloads are also within
the Fort Saskatchewan area. These are local area issues for double contingency outages and
can likely be mitigated through operating procedures. Local cogeneration development will
either eliminate or reduce the overloads.
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South of Keephills-Ellerslie-Genesee cutplane
The South of Keephills-Ellerslie-Genesee (SOK) cutplane is defined as the part of the system
south of the Keephills, Ellerslie and Genesee 500 kV loop. This cutplane is used to monitor
flows from generation in the north to loads in the south.
To simulate flow increases on this cutplane, imports from B.C. were gradually decreased
(or for exports increased) while increasing the generation in the Wabamun Lake, Edmonton
and Fort McMurray areas.
The initial starting point of flows on the SOK were about 2,050 MW. Results of the studies
indicate that overloads begin to occur on underlying 138 kV systems when flows increase
by about 750 MW or about 2,800 MW total. These overloads occur for double contingency
outages and could be mitigated through operating procedures. However, as flows increase
the number of overloads increase and solutions involving additional facilities might need
to be considered. Based on the assessment of the projected load growth in the south,
it is anticipated that the reinforcement of the 138 kV system will be required between
2025 and 2030. This will depend on generation additions in the south that may further
delay the project.
South region
The intent of the South region assessment was to determine the amount by which wind
generation in the south could increase before the system between the wind generators
and the load centres in and near Calgary begins to overload. For this reason, the loads were
increased in the greater Calgary area (which includes Calgary, Seebee, Strathmore/Blackie,
High River and Airdrie) and wind generation was increased in the south.
The results show that wind could increase by about 500 MW before the first limit is reached.
The overloads are local 138 kV issues in the southwest near Peigan and the southeast
near Medicine Hat. Major issues do not show up until the wind generation is increased
by about 1,000 MW.
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4.5 regioNAl trANsmissioN system ProJeCts
The province is divided into five major planning regions: Northwest, Northeast, Edmonton,
Central and South. This allows for a thorough assessment of the transmission system down
to a voltage of 69 kV level. The regional split is based on the unique load and generation
characteristics of various parts of the province. The primary driver for the regional
assessments comes from both load and generation customer connection requests.
In addition to the regional specific assessments, the ability of the bulk system to move
power between the regions is also assessed.
4.5.1 Northwest region
4.5.1.1 Overview
The Northwest region of Alberta is a large geographic area located northwest of the
Edmonton region. 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. The
Northwest region represents approximately one-third of the area of the province and about
one-tenth of total load. The major transmission facilities of the existing Northwest region
are shown in Figure 4.5.1-1.
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BENBOW
CARMON
NIPISI
KINUSO
KAYBOB
NORCEN
WAPITI
LUBICON
RYCROFT
DAISHOWA
ELMWORTH
HOTCHKISS
MEIKLE
SIMONETTEFOX CREEK
WHITECOURTKAKWA RIDGE
HINES CREEK
KIDNEY LAKE
H.R. MILNER
SADDLE HILLS
DOME CUTBANK
NARROWS CREEK
BOUCHER CREEK
CADOTTE RIVER
KSITUAN RIVER
VIRGINIA HILLS
ZAMA
MELITO
BASSETT
HAMBURG
LITTLE SMOKY
LOUISE CREEK
KEG RIVER
BLUMENORT
KEMP RIVER
HAIG RIVER
RAINBOW LAKE
SULPHUR POINT
CHINCHAGA RIVER
Grande Prairie
High Level
Grande Cache
Peace River
Swan Hills
Slave Lake
Fairview
Falher
Beaverlodge
Valleyview
Wembley
Manning
Sexsmith
McLennan
Spirit River
High Prairie
Figure 4.5.1.1-1: Existing northwest transmission system
SUBSTATIONS
Existing transmission lines
69 kV/72 kV
138 kV/144 kV
240 kV
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load (MW) 2010 winter peak 1,039 2020 forecast winter peak 1,450
generation (MW) Current installed 798 2020 forecast installed 1,330 – 1,800
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Expected growth
The load for the Northwest region at the time of AIL peak is expected to grow from the
2010 actual of 1,039 MW to around 1,536 MW by 2020. This load growth is generally
expected to come from forestry and gas development both in Alberta and the Fort Nelson
area in British Columbia.
Generation in the region is currently 798 MW made up of predominantly gas-fired generation.
The existing H.R. Milner coal plant (145 MW) is located in this region and is expected to
retire by 2020. Generation resources available for development include coal, gas, hydro,
biomass and wind. Generation capacity in the region is expected to reach between 1,330
and 1,800 MW by 2020, with the addition of gas-fired capacity in the Dunvegan hydro project
and the Swan Hills Synfuel underground coal gasification project. There is also potential for
an expansion at the H.R. Milner site.
Current conditions
Very long transmission lines in the Northwest region result in voltage stability issues and
are addressed by the requirement for transmission must-run (TMR). Projects are underway
to relieve this issue; however, TMR will be required beyond 2012 until transmission
reinforcement can be built.
The 144 kV transmission system in the Grande Prairie area will be at capacity due to
load growth and generation additions. TMR services are required to support this region
to mitigate voltage violations throughout the local area system.
Existing 72 kV systems in the region have exceeded their design capability and require
replacement due to age.
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4.5.1.2 Status of projects
In 2006, the AUC approved the facilities identified in the Northwest Alberta Transmission
NID to alleviate the voltage issues in the northwest corner of the province. The first phase
of the transmission development included adding capacitor banks and reactive support
devices, a 240 kV line from Brintnell to Wesley Creek and the addition of four new 144 kV
transmission lines. Most of these enhancements have been completed with only two 144 kV
lines (Ring Creek to Rainbow Lake and Sulphur Point to High Level) yet to be completed. In
the short term, the AESO is planning the addition of reactive support devices at Hotchkiss
substation in a continued effort to manage voltage fluctuation in the region.
The LTP identifies the need to build a double circuit 240 kV line from Little Smoky to a
240/144 kV substation near Grande Prairie, as well as providing enhancements to the
associated 144 kV lines in order to alleviate overloading on facilities within and to the
Grande Prairie area.
To alleviate low voltage conditions and replace aging infrastructure in the Slave Lake area,
upgrade plans include extending 144 kV lines into the area and decommissioning parts
of the aging 72 kV circuits.
The H.R. Milner 145 MW coal plant is expected to retire in 2017. Plant owner Maxim Power
has indicated its plans to develop an expanded 500 MW supercritical pulverized coal plant
at the site prior to the existing plant’s retirement. In the event plans to expand the coal plant
do not move forward, the existing site would also be attractive for the possible development
of a new gas-fired combined cycle unit given the existing infrastructure, water and air
permits. The existing 144 kV lines that move power from H.R. Milner to the load centres
are inadequate to carry the increase in generation. As a result, a double circuit 240 kV line is
proposed between H.R. Milner and the new substation near Grande Prairie. This transmission
project will be directly linked to the timing of the new H.R. Milner generating facility.
In addition to projects identified through the detailed system assessment process, it is
expected that new distribution customer points of delivery (POD) will be requested. The
need for these distribution PODs often surfaces in a very short (one to two year) timeframe.
To respond to the uncertainty and yet acknowledge and assess these possibilities, this LTP
includes the assumption that four substations will be requested in the Northwest region in
the next 10 years.
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table 4.5.1.2-1: northwest region transmission projects
year in cost estimate service Project description (2011 $ millions)
2013 North Conversion of the 72 kV system $65 Central to 144 kV serving High Prairie and Slave Lake
2014 Otauwau- A 144 kV line from Otauwau to $18 Slave Lake Slave Lake and conversion of Slave Lake substation to 144 kV
2015 Grande A double circuit 240 kV line from $287 Prairie Little Smoky to a new 240/144 kV substation near Grande Prairie and related 144 kV upgrades
2015 Hotchkiss Add 10 MVAr reactor banks $6 reactive at Hotchkiss substation support
2015-2018 H.R. Milner A double circuit 240 kV line $164 connection from H.R. Milner to the proposed 240/144 kV substation near Grande Prairie
2011-2020 Distribution Four distribution substations $100 PODs
total $640
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4.5.1.3 Unique challenges, uncertainties and concerns
The current plan for the northwest is heavily dependent on the assumption that two large
generators will be developed in the area. If either or both of these projects do not proceed
as anticipated, the local area transmission plan will need to reflect this change, and
significant transmission reinforcement will still be required to support anticipated new
loads in the region.
The potential also exists for renewable generation such as hydro and wind to be added to the
system in the northwest post 2020. Should this source of generation develop, it will impact
the need for local as well as inter-regional transmission reinforcement.
There is also potential for oilsands development in the Peace River area that could impact the
requirement for local area transmission reinforcement. The re-termination of the east end of
the Brintnell-Wesley Creek 240 kV line from Brintnell to Livock will help support load growth
in the Peace River area.
Unconventional oil and gas resource development in the Drayton Valley and Hinton-Edson
areas is a potential driver for additional load growth. The load forecast in the LTP accounts
for some growth in the area. The AESO will continue to monitor the development to assess
if further transmission development is required.
In addition to the uncertainty within Alberta, BC Hydro has forecast significant load growth
in the Fort Nelson, B.C. region that exceeds the load forecast used in the development of
the Northwest Alberta Transmission NID. The Fort Nelson area is connected to the Alberta
system via a 144 kV line supplied from the Rainbow Lake substation. Additional TMR
services may be required to support this incremental load until new transmission facilities
can be constructed. Additional transmission facilities beyond those identified in the NID
may be required for the Rainbow Lake area. Possible transmission reinforcements required
to serve additional B.C. loads are not included in the LTP.
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4.5.2 Northeast region
4.5.2.1 Overview
The Northeast region of Alberta is bordered 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 Township 60. This region includes Fort McMurray, Athabasca/Lac La Biche, Cold Lake
and Fort Saskatchewan. The major transmission facilities of the Northeast region are shown
in Figure 4.5.2.1-1.
Expected growth
The majority of the electrical load and generation in the region is located at oilsands sites
surrounding the City of Fort McMurray and in the Cold Lake area. This region is unique
as it has significant behind-the-fence load and generation connected to the grid as
industrial systems.
The Northeast region is expected to experience the greatest load growth of all the regions
over the next 10 years. This is due in large part to the expansion of the oilsands and
secondary industries in the municipalities in the region. The current load in the Northeast
region is predominantly industrial and makes up 2,349 MW, or 23 per cent of the 2010 AIL
peak load. Load in the region is expected to grow to 4,078 MW in 2020, a significant increase
from current levels.
Generation in the region is predominantly gas-fired generation at oilsands sites. There is
currently 3,001 MW of generation capacity in the area, accounting for about 23 per cent
of Alberta’s total installed generation capacity. Through the continued development of
cogeneration at oilsands sites, generation capacity in the region is expected to increase to
4,865 MW by 2020. There is uncertainty surrounding the amount of cogeneration the industry
will develop with their oilsands operations. Scenario and sensitivity studies were considered
in Section 4.4.5 to address this uncertainty.
Current conditions
Fort mcmurray area – The majority of Northeast region growth is expected to occur in this
area. Load growth is represented by major oilsands facilities that can be as high as 200 to
300 MW each. These proposed facilities are in pockets where oilsands development is
expected to occur and are generally located:
n north of Fort McMurray
n northeast of Wabasca (Livock)
n west of Dover
n in the Christina Lake area
n in Algar-Kinosis (south of Fort McMurray).
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CROW
BOYLE
DOVER
ALGAR
AURORA
MARIANA
WABASCA
KINOSIS
LEISMERCONKLIN
LACOREY
LINDBERGH
WINEFRED
MARGUERITE LAKE
PRIMROSE
MAHNO
FOSTER CREEK
COLINTON
CLYDE
FLATBUSH FLAT LAKE
WAUPISOO
BRINTNELL
HEART LAKE
JOSLYN CREEK
WHITEFISH LAKE
REDWATER
AMELIA
GREGOIRE
MCMILLAN
Athabasca
Firebag
CHRISTINA LAKE
Fort McMurray
Bonnyville
Elk PointLegal
Cold Lake
Lac La Biche
Figure 4.5.2.1-1: Existing northeast transmission system
SUBSTATIONS
Existing transmission lines
69 kV/72 kV
138 kV/144 kV
240 kV
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northeast
load (MW) 2010 winter peak 2,349 2020 forecast winter peak 4,078
generation (MW) Current installed 3,001 2020 forecast installed 4,865
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cold lake area – The 144 kV transmission system in this area is near capacity due to high
generation currently flowing out of the area. In addition, new generation is expected to be
connected in the northern part of the Cold Lake transmission system. Over the next 10 years
loads in this area should absorb some of this generation and unload the transmission system.
Regardless, new transmission facilities will be required to ensure supply can reach the new
loads recognizing oilsands developers have the capability and the desire to deliver excess
generation into the grid.
athabasca/lac la Biche area – The 138 kV transmission system in this area is near its
capacity due to continuing load additions. Over the next 10 years, more pipeline pumping loads
are expected that will cause both voltage and thermal violations throughout the local system.
Fort Saskatchewan area – Heavy oil upgrader projects are being proposed in the
Fort Saskatchewan area. A 240 kV transmission system will be developed to deliver power
to these loads. Associated load growth is anticipated for the 138 kV systems in support
of upgrader projects.
4.5.2.2 Status of projects
Conceptual plans have been developed for the four planning areas that comprise the
Northeast region as described below.
Fort McMurray area
Reactive power support is required in the Fort McMurray area to mitigate voltage
fluctuations, transient swings and increased inertia of the larger Fort McMurray electrical
system. These issues either individually or together can impact the stability of the
transmission system. The reactive power project includes the addition of capacitor banks
and reactive power devices at strategic substations. Also, under certain conditions the
voltage on the easternmost 240 kV circuit to Fort McMurray can collapse. This problem can
be mitigated in the short term by re-terminating the line that now goes from Whitefish to
Leismer, in and out of Heart Lake. The stability and operational flexibility issues mentioned
earlier can also be partially mitigated by interconnecting the east and central 240 kV supply
lines with a short 240 kV line between Algar and Kinosis.
The current 240 kV line configuration north of Fort McMurray does not allow the flexibility
necessary to ensure the system can be operated reliably. The Thickwood 240 kV switching
station will provide that flexibility. This station will ultimately serve as the terminus for the
proposed 500 kV circuits from Genesee and Heartland to Fort McMurray.
Continued load growth in the City of Fort McMurray requires additional supply to the city.
The Salt Creek Project includes a 240/144 kV substation south of the city along with related
144 kV enhancements. This substation will also be the south terminal of the North of
Fort McMurray 240 kV loop.
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There are several areas within the Northeast region that will see continued oilsands activity
in the form of bitumen extraction, refining and pipeline facilities. These projects are driven
by the need to connect large customer loads and include:
n The North of Fort McMurray area double circuit 240 kV loop from Joslyn Creek east
and then south to a new substation (Salt Creek) near Fort McMurray to connect
customers in that area.
n Livock 240/144 kV substation and related 144 kV lines will connect the initial large
customer loads west and south of Fort McMurray.
n A 240/144 kV substation at Algar will alleviate the 144 kV system south of
Fort McMurray currently operating at its design capacity.
n A 240 kV loop from Livock to Joslyn Creek will supply oilsands development
in the area west and northwest of Fort McMurray.
n A 240 kV loop from Heart Lake to Christina Lake will connect the potential oilsands
extraction facilities in the Christina Lake area.
Cold Lake area
New 144 kV transmission facilities are required to mitigate overloads in the area as well as to
accommodate the expected addition of new generation facilities and their associated loads.
These enhancements are included in the Central East Transmission Development that is
included as part of the Central region projects.
Athabasca/Lac La Biche area
The area 138 kV transmission system will be strengthened by the addition of a new 138 kV
circuit in the area to pick up additional pipeline loads.
Fort Saskatchewan area
There is a need to reconfigure the 240 kV system in the Fort Saskatchewan area to provide
increased operational flexibility. The first project consists of cutting one of the 240 kV circuits
in and out at Josephburg substation and restoring the capacity limits on three of the 240 kV
circuits. The second project driven in part by upgrader expansion includes a 240 kV
transmission extension from the Heartland 500/240 kV substation.
Similar to the Northwest region, in addition to projects identified through the detailed system
assessment process, it is expected that new distribution customer points of delivery (POD)
will be requested. The need for these distribution PODs often surfaces in a very short (one
to two year) timeframe. To respond to the uncertainty and yet acknowledge and assess these
possibilities, this LTP includes the assumption that four such substations will be requested in
the Northeast region in the next 10 years.
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4.5.2.3 Northeast region transmission projects
table 4.5.2.3-1: northeast region transmission projects
year in cost estimate service Project description (2011 $ millions)
2011 Athabasca Upgrade telecom in area $20 telecom upgrade
2012 9L66 240 kV line 9L66 240 kV line relocation $1
2012 Livock 240/144 kV substation and two $24 144 kV lines to customer facilities
2012 Northeast Capacitor banks at Dover, Whitefish $16 reactive and Leismer substations power
2012 Salt Creek 240 kV substation south of $30 Fort McMurray and 144 kV line to Hangingstone
2013 Fort Re-terminate 240 kV line in and $6 Saskatchewan out at Josephburg and increase near term rating on three 240 kV lines
2013 North of 240 kV double circuit line from $197 Fort McMurray Kearl Lake to Salt Creek and 240 kV switching stations at Kearl Lake and Black Fly
2015 Algar 240/144 kV substation tying adjacent $26 240 kV and 144 kV lines together
2015 Athabasca 240/138 kV transformer at Whitefish Lake $124 and 138 kV double circuit line to 794L (split 794L) and continue on to Boyle substation
2015 Christina 240 kV double circuit line from $350 Lake Heart Lake to a new 240/138 kV substation near Christina Lake
2015 Heart Lake Re-termination of the Whitefish- $8 Leismer 240 kV line in and out at Heart Lake
2015 Heartland Second 500/240 kV transformer at $69 240 kV Heartland and 240 kV double circuit second loop line to 942L tap between Lamoureux and Josephburg
2015 Thickwood 240 kV switching station northwest $173 of Fort McMurray and re-termination of four 240 kV lines in and out at Thickwood
2015-2020 Livock-Joslyn 240 kV double circuit $342 240 kV line from Livock to Joslyn
2020 Algar-Kinosis 240 kV line between Algar $61 and Kinosis substations
2011-2020 Distribution Four distribution substations $100 PODs
total $1,547
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4.5.2.4 Unique challenges, uncertainties and concerns
The greatest uncertainty for regional transmission in the Northeast region is the speed at
which the oilsands development will progress. The dates in Table 4.5.2.3-1 are based on
customer connection requests. The potential for considerable expansion is seen in the area
west and south of Fort McMurray as well as in the Christina Lake area. The LTP assumes
expansion in these three areas; however, additional transmission reinforcement may be
required if these areas grow to their full potential. If oilsands development slows, some of
the transmission projects can be delayed. The AESO continues to monitor development
to ensure transmission is in place ahead of need for customers to connect to the system.
The load and generation developments in the Northeast region are expected to generally
balance each other. There is potential for the situation to rapidly swing from being balanced
to turning into a load centre or supply area. Transmission thermal overloads and voltage
fluctuations are a concern and transient swings and increased inertia of the larger
Fort McMurray electrical system may also impact the stability of the transmission system.
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4.5.3 edmonton region
4.5.3.1 Overview
The Edmonton region is located approximately in the centre of the AIES and includes the City
of Edmonton and the Wabamun and Wetaskiwin areas. The region is bordered on the south
by the Central region and on the north by the Northeast and Northwest regions. The
Edmonton region is a major generation centre in the province. It is also the key hub for the
transmission network connecting the northwest, northeast and south areas of the AIES bulk
transmission systems through 240 kV lines.
The current Edmonton region system is comprised of transmission lines and substations that
operate at 500 kV, 240 kV, 138 kV and 69 kV. Figure 4.5.3.1-1 shows the existing transmission
system in this region.
Expected growth
Load in the Edmonton region at the time of AIL peak is expected to grow from the 2010
actual of 2,093 MW to around 2,780 MW by 2020. This load growth generally comes from
the residential and commercial load centres in Edmonton. As mentioned, the Edmonton
region is a major generation centre in the province with 4,457 MW or 34 per cent of Alberta’s
total installed generation capacity. Most of this generation capacity is baseload coal-fired
plants located around Wabamun Lake.
Generation capacity in the area is expected to change over time with the potential for both
retirement and addition of units. The aging coal-fired units in the area are expected to retire
once they reach their end of life. Generation development in the region will be a function
of response to new environmental standards, meaning that total generation may decrease
or increase from the current level of 4,457 MW to between 4,385 MW and 5,420 MW.
The noted change in the generation fleet includes the addition of Keephills 3 unit currently
under construction and gas-fired capacity additions, specifically the potential repowering
of brownfield sites in the Wabamun area with gas-fired combined cycle facilities.
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NORTH BARRHEAD
YASA
BARDO
ONOWAY
CARVEL
BUFORD
BEAMER
ERVICK
PONOKA
SUNDANCE
KINGMAN
BRETONA
GENESEE
WABAMUN
BELLAMY
REDWATER
DEERLAND
BIGSTONE
CELENESEENTWISTLE
WETASKIWIN
BONNIEGLEN
NELSON LAKE
PIGEON LAKE
EAST CAMROSE
COOKING LAKE
LAC LA NONNE
WHITEWOOD MINE
TRUWELD GRATING
SOUTH MAYERTHORPE
KEEPHILLS
GLENEVIS
DOMEELLERSLIE
NISKU
NAMAO
Smoky Lake
St. Albert
Camrose
Spruce Grove
Stony Plain
Devon
Morinville
Beaumont
Tofield
Gibbons
Calmar
Mayerthorpe
Bon Accord
Leduc
Fort Saskatchewan
Millet
Lamont
Bruderheim
Viscount
Edmonton
Figure 4.5.3.1-1: Existing Edmonton transmission system
SUBSTATIONS
Existing transmission lines
69 kV/72 kV
138 kV/144 kV 500 kV
240 kV
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Edmonton
load (MW) 2010 winter peak 2,093 2020 forecast winter peak 2,780
generation (MW) Current installed 4,457 2020 forecast installed 4,385 – 5,420
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Current conditions
The main source of electrical generation for the entire province is situated near Wabamun
Lake in the Edmonton region. There is more than 4,000 MW of baseload generation
connected to the AIES near Wabamun Lake to support various load centres, including Central
and South Alberta loads, Northwest region loads, Edmonton area loads and major industrial
loads located in the Fort Saskatchewan area. Generator instability and transmission overload
limit transfers between Wabamun and Edmonton during peak load periods. Transfers from
Wabamun south are also limited due to generator instability and transmission overloading.
There are major thermal overloads of transmission facilities throughout the Edmonton region.
The 138 kV transmission paths from Wabamun to Edmonton, Edmonton to Leduc and
from East Edmonton to the Fort Saskatchewan area are weak sections during peak load
conditions. As well, most of the voltage violations occur in the Edmonton and Wetaskiwin
areas due to weak system support. Within the City of Edmonton there are some thermal
overload issues in the 72 kV system.
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4.5.3.2 Status of projects
The 2009 LTP included several upgrades to the 240 kV system between Wabamun and
Edmonton as bulk system projects to alleviate system constraints in the region. Those
upgrades are underway. In addition, a new 240/138 kV substation is proposed to reinforce
the Wabamun area 138 kV supply by interconnecting to Acheson and Devon.
The existing lines in the North Calder, Viscount and St. Albert areas of the Edmonton region
are overloaded under certain conditions. A new 138 kV line between Viscount and North
Calder will address this issue.
Continued load growth in the Leduc area is resulting in the 138 kV system south of Edmonton
being overloaded for various contingencies. A new 240/138 kV supply in the vicinity of Leduc
will alleviate this problem. Overloading of these lines occurs when outages are experienced
on the 240 kV lines south from the Edmonton region.
Low voltage in the Onoway area north of Wabamun Lake is a problem under certain
conditions. This problem will be resolved with the addition of a capacitor bank at
Onoway substation.
The cables that supply the Garneau substation in the University of Alberta area of the City of
Edmonton are aging and need to be replaced. The plan is to replace the existing cables with
new higher capacity cables.
With the anticipated retirement of Sundance 1 and 2 (576 MW coal) and their anticipated
replacement with Sundance 7 (800 MW combined cycle), the net increase in generation
cannot be moved out of the Sundance area with the current system. The proposal is to
extend the Keephills-Ellerslie-Genesee (KEG) 500 kV loop from Keephills to Sundance. This
extension requires about 12 km of new line and will strengthen the 500 kV loop to Ellerslie.
The timing of this project will be driven by the timing of the addition of the Sundance 7
generation project.
Again, similar to the previous regions, in addition to projects identified through the detailed
system assessment process, it is expected that new distribution customer points of delivery
(POD) will be requested. The need for these distribution PODs often surfaces in a very short
(one to two year) timeframe. To respond to the uncertainty and yet acknowledge and assess
these possibilities, this LTP includes the assumption that four such substations will be
requested in the Edmonton region in the next 10 years.
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4.5.3.3 Edmonton region transmission projects
table 4.5.3.3-1: Edmonton region current transmission projects
year in cost estimate service Project description (2011 $ millions)
2012 Wabaumn- Complete the work which includes $153 Edmonton reconductoring one 240 kV lines, debottleneck re-terminating 240 kV lines on the Wabamun end and the Edmonton end, and adding a phase shifting transformer at Livock
2013 Garneau Replace underground cables $150 between Rossdale and Garneau
2013 Onoway Add 10 MVAr capacitor $3 bank at Onoway
2013 South of 240/138 kV substation near $57 Edmonton Nisku and 138 kV enhancements
2013 Southwest 240/138 kV substation near Edmonton Acheson and 138 kV enhancements $95
2014 North 138 kV line from North Calder $34 Edmonton to Viscount
2015-2017 Extend KEG 500 kV double circuit line from $119 loop to Keephills to Sundance and a Sundance 500/240 kV substation at Sundance
2011-2020 Distribution Four distribution substations $100 PODs
total $711
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4.5.3.4 Unique challenges, uncertainties and concerns
The Edmonton region is a major corridor for electricity flows between the Northeast,
Central and South regions. The power requirements of the major oil production facilities
in the Northeast region can have a significant impact on transmission infrastructure in the
Edmonton region. The retirement of coal-fired generation facilities and possible replacement
with combined cycle generation could impact the flows through and out of this region.
The City of Edmonton transmission network consists primarily of a 72 kV system made up
of high pressure oil-filled pipe type cables servicing 72 kV to 15 kV bulk-type substations, all
of which are nearing (or in some cases beyond) their life expectancy. A near-term goal will be
to determine if the 72 kV voltage level is still appropriate for the service expected. It will also
be necessary to determine if the existing cable technology – oil-filled pipe type cable – is still
appropriate, and what changes and upgrading are required to the Edmonton substations to
modernize and service increasing load and load densities.
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4.5.4 Central region
4.5.4.1 Overview
The Central region spans the province east to west between Edmonton and Calgary.
The major transmission facilities of the Central region are shown in Figure 4.5.4.1-1.
Expected growth
Electricity demand in the Central region at the time of AIL peak is expected to grow from
1,505 MW in 2010 to 2,251 MW in 2020. This load growth generally comes from pipeline and
industrial activity in the region as well as residential and commercial expansion in Red Deer.
The east side of the Central region is a major path for pipelines between Edmonton and the
Northeast region, as well as to other markets. The increase in load in the region is partly a
function of the planned expansion in this pipeline corridor.
Current generation capacity in the region totals 1,837 MW. The generation is a mix of
hydro, coal-fired and industrial gas-fired cogeneration. Generation resources available for
development in the region include gas, wind, hydro and coal. Generation capacity in the region
is expected to increase to between 2,130 MW and 2,630 MW by 2020, with the additions being
primarily gas-fired capacity and wind generation. A number of wind projects in the Central
region totalling over 1,200 MW have applied for connection to the grid. The Battle River units
3 and 4 are expected to retire prior to 2020 following the expiration of the Power Purchase
Arrangements in 2013, offsetting some of the new generation additions in the area.
Current conditions
With its location in the middle of Alberta, there is a significant transfer of energy through
this region on the north to south path between Edmonton and Calgary on the existing
240 kV system.
Hanna and Wainwright areas
One of the key drivers for load growth in the Wainwright and Hanna areas is the projected
building of a number of new pipelines for carrying bitumen and oil products from oilsands
projects to markets in the U.S. and other proposed destinations.
In addition to load, the AESO has received system access service applications for the
connection of close to 1,200 MW of wind generation projects in the Central region as of
April 30, 2011. The majority of the build is anticipated in the Hanna area. This area includes
coal-fired generation at Battle River and Sheerness. As generation in the area increases,
it results in a generator instability limit on the 240 kV circuits going south from Sheerness.
Red Deer and Didsbury areas
Load growth in the Red Deer and Didsbury areas will result in overloading the existing 138 kV
system. In addition, there is an operational constraint associated with the Joffre generation
due to limited capacity on the 138 kV transmission system. Thermal line loading limits
transfers in and out of Joffre under certain load and generation conditions.
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VILNA
NEVIS
STROME
CORDEL HAYTER
ROWLEY
BRAZEAU
BIGFOOT
MONITOR
BENALTO
HEISLER
BRAZEAU
ST. PAUL
EDGERTON
PINEDALE
METISKOW
DELBURNE STETTLERSTRACHAN
ECKVILLE
HARDISTY
MARLBORO
GULF ROBB
HARMATTAN
ELK RIVER
LODGEPOLE
DALEHURST
SEDGEWICK
LIMESTONE
BUCK LAKE
COLD CREEK
WILLINGDON
BIG VALLEY
IRISH CREEK
FICKLE LAKE
COAL VALLEY
SUNKEN LAKE
NORTH HOLDEN
ASTORIA RIVER
BUFFALO CREEK
SULLIVAN L.
BIGHORN PLANT
WILLESDEN GREEN
CARDINAL RIVER
SUNDRE
CADOMIN
VETERAN
RICHDALE
Cheviot
Watson Creek
Red Deer
Lloydminster
Drumheller
Hinton
Lacombe
Vegreville
Sylvan L.
DraytonValley
Wainwright
Killam
Didsbury
Rocky MountainHouse
Three Hills
Two Hills
Briker
Ribstone Creek
Vermilion
Stettler
Hanna
CastorCoronation
Edson
Provost
Oyen
BICKERDIKE
Figure 4.5.4.1-1: Existing central transmission system
SUBSTATIONS
Existing transmission lines
69 kV/72 kV
138 kV/144 kV
240 kV
4.0 AESO Analysis and Planning Results
central
load (MW) 2010 winter peak 1,505 2020 forecast winter peak 2,251
generation (MW) Current installed 1,837 2020 forecast installed 2,130 – 2,630
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Central East and Central West areas
The central east area is approximately between Cold Lake and Vermilion and east of
Edmonton. The central west area includes Wabamun Lake-Drayton Valley and extends west
to Edson-Hinton. Improvements are required in part to supply general area load increases
and to replace aging facilities. Although the Cold Lake area is part of the Northeast region,
enhancements to support Cold Lake have been included in the central east area.
4.5.4.2 Status of projects
Transmission development is required in the Red Deer area to meet projected load growth.
These enhancements include three 240/138 kV substations in the area as well as several
138 kV transmission line upgrades.
The plan for the Hanna area was developed to meet the additional pipeline loads and
wind generation and convert parts of the aging 69 kV and 72 kV systems to 138 kV. To
accommodate the pipeline loads, the plan is to construct a 240 kV loop from Anderson to
Metiskow with two new 240/144 kV substations between Oyen and Metiskow. The aging
69/72 kV system will be enhanced with 138 kV lines and substation upgrades as well as the
addition of capacitor banks and reactive power devices for voltage support. Wind integration
will require the construction of a new double circuit 240 kV line and a substation west of
Anderson (in the South region). Besides supplying pipeline loads, the Hanna area project will
also relieve a constraint south of the Sheerness generation facility. The 240 kV loop between
Anderson and Metiskow will be constructed in two stages. The first will include double circuit
towers with one side strung; stage two will string the second side of the towers.
In addition to the larger Hanna project, the LTP identifies a need to convert some of the aging
69 kV and 72 kV systems to 138 kV in the north of the region near Stettler and in the south of
the region near Oyen by 2020.
Aging infrastructure, overloads and low voltages in the central east area of the province (the
large area east of Edmonton from Cold Lake in the Northeast region to Hardisty) requires a
substantial rebuild of the 138 kV and 144 kV systems as well as decommissioning of aging
69 kV and 72 kV lines. The central east project includes multiple 138 kV upgrades to meet
the needs of this area of the province.
Similar to the central east area, the central west area also has aging infrastructure,
overloads and low voltage conditions. This area extends from Wabamun and Drayton Valley
in the Edmonton region to Hinton in the west. Enhancements to the 138 kV system and
reconfiguration in the Edson-Hinton area, as well as replacement of aging 69 kV circuits in the
Wabamun-Drayton Valley area, will relieve the system overloads and low voltage conditions.
In addition to projects identified through the detailed system assessment process, it is
expected that new distribution customer points of delivery will be requested. The need
for these distribution PODs often surfaces in a very short (one to two year) timeframe.
To respond to the uncertainty and yet acknowledge and assess these possibilities, this
LTP includes the assumption that four such substations will be requested in the Central
region in the next 10 years.
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4.5.4.3 Central region transmission projects
table 4.5.4.3-1: central region current transmission projects
year in cost estimate service Project description (2011 $ millions)
2011-2012 Yellowhead Conversion of the 69 kV systems $123 to 138 kV from Wabamun to Drayton Valley and Wabamun to Barrhead; reconfiguration and enhancements to the 138 kV system in the Edson-Hinton area
2012-2014 Central East Extensive enhancements and $352 reconfiguration of the 138 kV and 144 kV systems east of Edmonton between Cold Lake and Hardisty
2012-2017 Red Deer Three 240/138 kV substations near $204 area Ponoka, Innisfail and Didsbury; major reconfiguration of the 138 kV system in and around the city of Red Deer
2014-2017 Hanna area A new 240/144 kV substation $909 near Hardisty with a 240 kV double circuit line connecting the new substation to the 240 kV line between Cordel and Hansman Lake; a 240 kV double circuit line from Anderson to Oyen and north to Hansman Lake with a new 240 kV SW
2018 Hanna 69 kV Conversion of parts of the 69 kV systems $66 near Stettler and Oyen to 138 kV
2011-2020 Distribution Four distribution substations $100 PODs
total $1,754
4.5.4.4 Unique challenges, uncertainties and concerns
The major driver for transmission development in the Central region is the anticipated
expansion of the pipeline corridor from Edmonton and the Northeast region through the east
side of the province and on to markets in the U.S. The speed at which new pipelines are
added could impact the timing of the Hanna area development. There is also potential for
substantial wind development east of Highway 2 between Edmonton and Calgary. This wind
generation could have an impact on the need and timing of 240 kV enhancements in the
Central region and between the Central region and other regions.
An intertie to Saskatchewan at Lloydminster is being proposed as a merchant facility.
Depending on the size of this intertie, additional transmission reinforcement in the central
east area might be required.
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4.5.5 south region
4.5.5.1 Overview
The South region of Alberta has as its south boundary the Canada-U.S. border. The region is
bordered on the north by the Central region and includes Calgary and the surrounding area.
The region is also bordered by B.C. and Saskatchewan on the west and east respectively.
The major transmission facilities of the South region are shown in Figure 4.5.5.1-1.
Expected growth
The South region is a major load centre in Alberta. Large load centres within the region include
Calgary, Lethbridge, Medicine Hat and the Empress industrial area. The region’s load at the time
of system peak was 2,917 MW in 2010, or 29 per cent of the province’s peak. By 2020 load is
expected to increase to 4,093 MW. This load growth comes mainly from general growth in the
industrial, residential and commercial sectors, and considers some pipeline expansion as well.
The region currently contains 2,919 MW of Alberta’s total installed generation capacity, made
up of a mix of hydro, coal-fired, gas-fired and wind. Currently, the majority (695 MW) of the
province’s 777 MW of transmission connected wind capacity is located in this region. Generation
development potential in the region consists mainly of gas-fired and wind facilities. The AESO has
received system access for a significant number of wind generation projects in the South region,
with 5,500 MW of the total 6,700 MW in the connection queue. Generation capacity in the region
is expected to increase to between 4,955 and 6,000 MW with the main additions again being
gas-fired and wind generation facilities.
Current conditions
The region has historically been a net importer of power from the rest of the AIES even though
the non-coincident peak load in the region is less than its generating capacity. The amount of
power flowing into the region depends on the output of wind generation in the region, which
is intermittent. The region has typically imported about five per cent of its annual energy
supply, which indicates it has almost enough generation to supply its own load.
The portion of the generation produced by wind generating facilities located in the South
region is expected to increase substantially over the next five years. Energy production from
these facilities will vary based upon the available wind to drive the turbines. During certain
wind conditions, the South region will have a surplus of power to deliver to the rest of
Alberta and export to B.C. and Saskatchewan through transmission interties.
The Calgary area is a major load centre for this region and the province with close to
25 per cent of Alberta’s total load requirement. TMR generation is required depending on the
availability of transmission system elements. The need to periodically call upon TMR generation
indicates that the transmission system is not adequate to serve the current load. TMR payment
represents costs to consumers that an investment in transmission would avoid.
The City of Calgary and the surrounding area continue to see increased demand as the
population continues to grow. Along with additional distribution growth, the bulk 240 kV
network that supplies power to the PODs will also require upgrades to keep pace with
the strong and steady growth in demand.
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HAYS
TABER
VULCAN
CONRAD
TILLEY
JENNER
WARNER
PEIGAN
MONARCH BURDETT
DRYWOOD
EMPRESS
ENCHANT
WARDLOW
DUCHESS
VAUXHALL
WATERTON
SUFFIELD
ANDERSON
GLENWOOD
COALBANKS
FINCASTLE
SHEERNESS
BULLPOUND
WESTFIELD
BULLSHEAD
CHIN CHUTE
PEACE BUTTE
EAST STAVELY
FORT MACLEOD
MCBRIDE LAKE
CHAPPICE LAKE
IRRICAN POWER
SPRING COULEE
WARE JUNCTION
MCNEILL
ST. MARY HYDRO
RAYMOND RESERVOIR
RANGE PIPE
BOWRONCOLEMAN
STIRLING
WEST BROOKS
Lethbridge
Medicine Hat
CrowsnestPass
Brooks
Redcliff
Cardston
Claresholm
Magrath
Bow Island
Raymond
Milk River
Granum
Picture Butte
Stavely
HillridgeLUNDBRECK
SEEBESPRAYLAKES
BANFF
HUSSAR
NAMAKA
MAGCAN
OKOTOKS
LANGDONJANET
HARTELL BLACKIE
BARRIER
GLEICHEN
COCHRANE
CARSELAND
POCATERRA
QUEENSTOWN
SPRINGBANKCALGARY
BEDDINGTON
HIGH RIVER
LAKE LOUISE
HORSE CREEKGHOST
EAST AIRDRIE
THREESISTERS
WEST CROSSFIELD
Airdrie
Canmore
Strathmore
Nanton
Turner Valley
Black Diamond
Figure 4.5.5.1-1: Existing South transmission system
SUBSTATIONS
Existing transmission lines
69 kV/72 kV
138 kV/144 kV 500 kV
240 kV
4.0 AESO Analysis and Planning Results
South
load (MW) 2010 winter peak 2,917 2020 forecast winter peak 4,093
generation (MW) Current installed 2,919 2020 forecast Installed 4,955 – 6,000
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4.0 AESO Analysis and Planning Results
Issues identified
The existing 240 kV and 138 kV system in the south is inadequate to support anticipated
wind generation development in this region. Recent enhancements, which include a 240 kV
double circuit line from Pincher Creek to Lethbridge, will help integrate wind; however, it is
not sufficient to meet anticipated wind development to 2020.
In addition to wind integration, load related thermal overloads and voltage violations
were identified in the Glenwood area in the southernmost part of the system from Waterton
to Stirling.
Thermal overloads and low voltages were identified in most of the region from Airdrie through
to the City of Calgary and south to High River in the 2015 and 2020 timeframe.
4.5.5.2 Status of projects
Continued load growth north of Calgary will result in overload and low voltage conditions on
the 138 kV system in that area. The preferred enhancement includes a 240/138 kV substation
east of Airdrie and local area 138 kV enhancements.
Parts of the transmission system within the city of Calgary are nearing the end of their operating
life. Also, increased loading on older 69 kV systems results in system overloads and low
voltages under certain conditions. This LTP defines several system enhancement projects
along with the replacement of aging infrastructure in order to upgrade the system:
n Replacement of the underground cables connecting downtown Calgary substations.
n Addition of 138 kV circuits and conversion of older 69 kV substations
in south Calgary to replace the aging 69 kV system.
n Addition of 138 kV circuits and conversion of older 69 kV substations
in north Calgary to replace the aging 69 kV system.
As Calgary continues to expand to the north and west, there will be a need for a 240 kV supply
in these areas. This supply is expected to be required sometime in the next 10 to 15 years.
To accommodate load growth and resolve voltage issues in the High River-Black Diamond
area, a new 138 kV line will be required from the proposed High River area 240/138 kV
substation and new Big Rock substation on to the Black Diamond substation.
The aging 69 kV system south of Highway 3 between Pincher Creek and Lethbridge is
reaching the end of its operating life and is subject to overloads and low voltages under
certain conditions. The recommended enhancement is to gradually replace the 69 kV system
with a 138 kV system.
High wind development north of Pincher Creek requires the installation of a 240 kV
substation to tie wind generators to the grid.
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4.0 AESO Analysis and Planning Results
In addition to projects identified through the detailed system assessment process, it is
expected that new distribution customer points of delivery will be requested. The need
for these distribution PODs often surfaces in a very short (one to two year) timeframe.
To respond to the uncertainty and yet acknowledge and assess these possibilities, the
LTP includes the assumption that four such substations will be requested in the
South region in the next 10 years.
4.5.5.3 South region transmission projects
table 4.5.5.3-1: South region current transmission projects
year in cost estimate service Project description (2011 $ millions)
2011 Calgary Replace existing 138 kV cables $66 downtown with higher capacity 138 kV cables cable replacement
2012 Fidler Fidler 240 kV substation $35
2013 Calgary Convert 69 kV system in south Calgary to $23 South 69 kV 138 kV and salvage part of the old system conversion
2015 Airdrie area 240/138 kV substation east of Airdrie $28 and a 138 kV double circuit line to connect to the existing 138 kV system
2013-2015 North Convert 69 kV system to 138 kV and $150 Calgary 69 kV salvage parts of the 69 kV system conversion
2016 Big Rock 138 kV line from Okotoks to Big Rock $24 to Black Diamond and salvage 69 kV line from High River to Black Diamond
2016 South Convert 69 kV to 138 kV from Pincher $48 Alberta 69 kV Creek to Cowley and from Stirling conversion to Magrath
2011-2020 Distribution Four distribution substations $100 PODs
total $475
4.5.5.4 Unique challenges, uncertainties and concerns
The largest planning challenge for the South region is the amount of wind generation that has
requested to be connected to the AIES. This is being addressed by the SATR development,
applying project staging and setting milestones for when various transmission components
are needed.
Generation development, both wind in the south and gas-fired generation in and around
Calgary, can impact the Foothills Area Transmission Development (FATD) project. The timing
of the west leg from Foothills substation to Sarcee substation is dependent on where and
when these forms of generation develop.
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4.0 AESO Analysis and Planning Results
4.6 loNg-term trANsmissioN PlAN Costs
The previous sections have discussed the transmission projects planned for 2011 to 2020
in Alberta. As part of the planning of those projects, estimates are prepared for the capital
costs and in-service dates of the transmission facilities expected to be required. This section
summarizes the costs of the transmission projects as estimated at the time this LTP was
prepared, and evaluates the impact of those costs on rates charged to users of the electric
system. These costs are submitted to the AUC as part of regulatory filings.
For projects for which a Needs Identification Document (NID) or a Facilities Application (FA)
have been filed, their cost estimates are more precise as they reflect more advanced project
definitions and prices. The prices typically represent quotes or bids for supply of specific
equipment, commodity or services. Consistent with ISO Rule 9.1 and AUC Rule 007, the
expected accuracy of the cost estimates for a NID is ±30% and for an FA is +20% to -10%.
These estimates are provided by the respective TFO per ISO Rule 9.1. About 60 per cent
of the project costs listed in Table 4.6.1-1 fall under this category.
The cost estimates for the projects that are in the planning stage are developed based on
the early stages of project definition and the conceptual expectation of the project. These
estimates are prepared by an independent consultant based on high-level functional
specifications prepared by the AESO. These estimates are further validated by the benchmark
data that the AESO continually updates based on data from recent projects in Alberta. These
cost estimates use factors and models based on characteristics of the projects (such as line
length and voltage level) rather than specific bid or tender prices or estimates provided by
TFOs. The expected accuracy for planning cost estimates is ±50%. About 40 per cent of
the projects listed in Table 4.6.1-1 fall into this category.
Figure 4.6-1 illustrates the total cost by type of cost estimate. The accuracy of the cost
estimates increases as the estimate moves from a planning estimate to the FA stage.
$10,000
$9,000
$8,000
$7,000
$6,000
$5,000
$4,000
$3,000
$2,000
$1,000
$0
2011
$ m
illio
ns
Range in the accuracy of the cost estimate
Facility Application Need Identification Document Planning
+ 20%
- 10% + 30%
- 30%
+ 50%
+ 50%
Figure 4.6-1: Projects by development stages and respective cost estimate accuracy
PagE 129
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4.0 AESO Analysis and Planning Results
The estimates of the capital costs and timing of the projects in this LTP were prepared or
confirmed in late 2010 and early 2011. Costs and timing are expected to change over time
as projects are more fully developed, as the factors affecting transmission requirements
change and evolve, and as the LTP is updated and revised. Updates to costs and timing
of projects are provided to stakeholders in AESO quarterly reports, also in accordance
with ISO Rule 9.1 on transmission facility projects.
Significant estimating uncertainty results from how far in the future the project is needed.
For example, the cost estimates for projects needed post 2020 are difficult to prepare
given that no dependable cost data for labour or commodity pricing is available at this time.
Because of this, the cost estimates for these projects are not shown. In addition, the scope
definition of many of these projects is subject to further development as more definitive
information associated with load and generation become available. The cost estimates
of these projects will be included in future updates of the LTP.
In addition to reporting on the quarterly project cost updates for projects in the NID or FA
stages (posted to the AESO website) and to provide more useful and up-to-date information
to stakeholders, for this LTP the AESO has summarized costs and timing of projects in this
section as well as in a separate Transmission Rate Impact Analysis posted on our website.
The AESO will regularly update the Transmission Rate Impact Analysis to reflect changes
to the capital costs and timing of projects identified in this LTP, including the most recent
estimate of the impact of those costs on transmission rates. The most recent update of the
Transmission Rate Impact Analysis is available on the AESO website at www.aeso.ca
4.6.1 Project cost estimates
Table 4.6.1-1 provides the cost estimate, timing, and estimate class for each project included
in this LTP. The projects are grouped geographically and listed in the same order as in
previous sections. Cost estimates are in 2011 dollars and include costs generally incurred
by TFOs such as engineering and supervision, allowance for funds used during construction
(AFUDC), distributed general and administrative costs, and contingencies. As the cost
estimates are in 2011 dollars, inflation may result in costs increasing when the projects are
placed in service and included in the rate base of TFOs. The impact of inflation is estimated
in the transmission rate impact analysis that follows in Section 4.6.2.
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AESO Long-term Transmission Plan
table 4.6.1-1: Projected cost estimates and timing: 2011-2020
year in cost estimate cost estimate Project description service (2011 $ millions) class
Bulk transmission system projects (including critical transmission infrastructure (cti))
South Calgary source (CTI) 2012 $37 FA
Heartland 500 kV (CTI) 2013 $537 FA
East HVDC (CTI) 2014 $1,622 FA
West HVDC (CTI) 2014 $1,329 FA
Bickerdike – Little Smoky 2015 $205 Planning
West Fort McMurray 500 kV (CTI) 2017 $1,649 Planning
9L15 retermination at Livock 2017 $40 Planning
South Area Transmission Reinforcement (SATR) 2011-2017 $2,287 NID
Foothills Area Transmission Development (FATD) 2014-2017 $711 Planning
Bulk transmission system projects subtotal – $8,417 –
northwest region
North Central 2013 $65 FA
Otauwau – Slave Lake 2014 $18 Planning
Grande Prairie 2015 $287 Planning
Hotchkiss reactive support 2015 $6 Planning
H.R. Milner connection 2015-2018 $164 Planning
Distribution points of delivery 2011-2020 $100 Planning
northwest region projects subtotal – $640 –
northeast region
Athabasca telecom upgrade 2011 $20 FA
9L66 240 kV line relocation 2012 $1 FA
Livock 2012 $24 FA
Northeast reactive power 2012 $16 FA
Salt Creek 2012 $30 FA
North of Fort McMurray 2013 $197 FA
Fort Saskatchewan near-term 2013 $6 Planning
Algar 2015 $26 Planning
Athabasca 2015 $124 Planning
Christina Lake 2015 $350 Planning
Heart Lake 2015 $8 Planning
Heartland 240 kV second loop 2015 $69 Planning
Thickwood 2015 $173 NID
Livock – Joslyn 240 kV 2015-2020 $342 Planning
Algar – Kinosis 2020 $61 Planning
Distribution points of connection 2011-2020 $100 Planning
northeast region projects subtotal – $1,547 –
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AESO Long-term Transmission Plan
As explained previously, costs and timing of projects will be regularly updated in the
Transmission Rate Impact Analysis, and the most recent update of the analysis should
be referred to for current information.
year in cost estimate cost estimate Project description service (2011 $ millions) class
Edmonton region
Wabamun – Edmonton debottleneck 2012 $153 FA
Garneau 2013 $150 Planning
Onoway 2013 $3 Planning
South of Edmonton 2013 $57 Planning
Southwest Edmonton 2013 $95 Planning
North Edmonton 2014 $34 Planning
Extend KEG loop to Sundance 2015-2017 $119 Planning
Distribution points of delivery 2011-2020 $100 Planning
Edmonton region projects subtotal – $711 –
central region
Yellowhead 2011-2012 $123 FA
Central East 2012-2014 $352 NID
Red Deer area 2012-2017 $204 NID
Hanna Area Transmission Development (HATD) 2014-2017 $909 FA
Hanna 69 kV 2018 $66 Planning
Distribution points of delivery 2011-2020 $100 Planning
central region projects subtotal – $1,754 –
South region
Calgary downtown cable replacement 2011 $66 FA
Fidler 2012 $35 FA
Calgary South 69 kV conversion 2013 $23 FA
Airdrie area 2015 $28 FA
North Calgary 69 kV conversion 2015 $150 Planning
Big Rock 2016 $24 Planning
South Alberta 69 kV conversion 2016 $48 Planning
Distribution points of delivery 2011-2020 $100 Planning
South region projects subtotal – $475 –
total, all projects 2011-2020 $13,545 –
Note: Totals and subtotals may differ due to rounding
4.0 AESO Analysis and Planning Results
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4.0 AESO Analysis and Planning Results
This Plan also discusses some projects that occur after the 2011-2020 period included in
Table 4.6.1-2. Two CTI projects were included in the 2009 LTP and have now been deferred
beyond 2020. A new project, North Calgary 240 kV supply, has also been identified for the
post-2020 period.
table 4.6.1-2: Projects with in-service dates beyond 2020
Project year in service
North Calgary 240 kV supply 2021
CTI: East Fort McMurray 500 kV 2021-2022
CTI: increase capacity of both 500 kV HVDC lines Post 2020
table 4.6.1-3: ltP capital cost summary by region
region Estimated cost (2011 $ millions)
cti total $5,174
HVDC $2,951
Heartland $537
Fort McMurray $1,649
Calgary $37
South $3,473
central $1,754
Edmonton $711
northeast $1,588
northwest $845
aiES total $13,545
4.6.2 transmission rate impact
Transmission facility owners (including both owners of existing regulated transmission
facilities and of future facilities resulting from a competitive process) will build, own, operate
and maintain the projects included in the LTP. The AESO pays owners for the use of their
facilities and recovers those costs through regulated rates charged for system access
service. Payments to the AESO for system access service are included in the transmission
charges on bills for electric service paid by all end-use consumers, whether industrial,
commercial, residential or farm.
The total cost of all transmission projects in this LTP is recovered over the life of the
transmission facilities, which typically last 40 or more years. Not all projects are built at the
same time and the impact of the projects in this LTP on customer rates will occur gradually
as they are placed in service over the years 2011 to 2020.
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In some cases, new transmission projects will reduce operating and maintenance costs
associated with older transmission facilities that are being replaced and/or removed.
Additional capacity resulting from new projects will allow flexibility in operation and permit
optimal management of the transmission system.
The transmission projects in this LTP will have other impacts on the costs of electric service.
For example, they will improve the efficiency of the transmission system and reduce system
losses. The transmission projects will also reduce costs resulting from transmission system
congestion that can prevent the operation of the most economical generation.
It is challenging to accurately determine the rate impact of the transmission projects, given
the various factors mentioned above and the changes to project cost estimates and timing.
To provide up-to-date information to stakeholders, the AESO has developed a rate impact
model for the Long-term Transmission Plan in working Microsoft Excel format on our website.
The model is updated regularly, and the current version is available at www.aeso.ca
Based on current transmission costs, the costs estimates and timing provided in
Table 4.6.1-1, and forecasts of increased volumes for system access service, the AESO
estimates that transmission costs will gradually increase up to $19/MWh (1.9¢/kWh)
over the years covered in this LTP. This would increase the electric bill for an average
residential consumer (using 600 kWh/month) by $11 per month from about $92 per
month in 2011 to about $103 per month in 2020. These estimates hold other costs
constant and do not include increases due to escalation of those other costs.
Similarly, for an average industrial customer, (80 per cent load factor), the average
charge for a megawatt of delivered power would increase from about $79/MWh
in 2011 to about $98/MWh in 2020.
The transmission rate impact analysis and related information on the AESO website
provide additional information on the cost estimates and timing of projects and will be
regularly updated. As well, the analysis provides a calculator to estimate the increase
in electricity costs for an individual industrial or residential service, due to the impact
of the transmission projects in the LTP. The model and calculator allow different
assumptions to be modified so that users may assess the sensitivity of the analysis
to different factors.
The impact analysis summarized in this section is based on cost estimates and timing
of transmission projects in the LTP and assumptions about other factors, all of which
were established in early 2011. Please refer to the most recent Transmission Rate
Impact Analysis for current information.
PagE 134
AESO Long-term Transmission Plan
4.0 AESO Analysis and Planning Results
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
$120
$100
$80
$60
$40
$20
$0
Ave
rage
res
iden
tial b
ill ($
/mon
th)
Energy, distribution and retail Transmission
$9/month $21/month
Ave
rage
ind
ustr
ial c
harg
es ($
/MW
h)
Energy Transmission
$16/MWh
$35/MWhTransmission
Energy
Figure 4.6.2-1: Transmission cost impact on residential and industrial customers
Residential
Transmission
Energy, distribution and retail
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
$120
$100
$80
$60
$40
$20
$0
Industrial
PagE 135
AESO Long-term Transmission Plan
$16,000
$14,000
$12,000
$10,000
$8,000
$6,000
$4,000
$2,000
$0
$ m
illio
ns
1,122
14,463
1,927
1,520
1,281 1,216
10,951
1,473
13,545
2009 LTP(2008 $)
Projects cancelled(2008 $)
Projectsdelayed
beyond 2020(2008 $)
Projectscompleted
or nearcompletion
(2008 $)
Escalation2008 to 2011
(2011 $)
Adjusted2009 LTP(2011 $)
New projectsand scopechanges(2011 $)
This LTP(2011 $)
New
Scope change
Figure 4.6.3-1: Reconciliation of this LTP and 2009 LTP costs
4.6.3 reconciliation of costs
The AESO assesses the requirement for and the scope of projects in the LTP on an ongoing
basis. Table 4.6.3-1 reconciles the projects in this LTP with the projects in the 2009 LTP
that have been cancelled, delayed or completed. Projects in the 2009 LTP were estimated
in 2008 dollars, and are subject to cost escalation when re-estimated in 2011 dollars in this
LTP. New projects have been added in this Plan, while others have been subject to changes
in scope.
The AESO plans to provide similar reconciliations to prior estimates as part of the updates
to the Transmission Rate Impact Analysis.
table 4.6.3-1: reconciliation of this ltP and 2009 ltP costs
description cost estimate ($ millions)
2009 ltP projects (2008 $) $14,463
Projects cancelled (2008 $) $(1,927)
Projects delayed beyond 2020 (2008 $) $(1,520)
Projects completed or near completion (2008 $) $(1,281)
Balance of projects remaining from 2009 ltP (2008 $) $9,735
Cost escalation, 2008 to 2011 (2011 $) $1,216
New projects (2011 $) $1,122
Scope changes for existing projects (2011 $) $1,473
total ltP projects to 2020 (2011 $) $13,545
The following figure and accompanying tables provide details on the reconciliation of the
costs between this LTP and the 2009 LTP.
4.0 AESO Analysis and Planning Results
PagE 136
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4.0 AESO Analysis and Planning Results
table 4.6.3-4: Projects from the 2009 ltP completed or near completion
Estimated cost in 2009 ltP region Project description iSd (2008 $ millions)
South Southwest New Goose Lake 240/138 kV 400 MVA 2010 $154 Alberta substation adjacent to Pincher Creek; transmission a new double circuit 240 kV line from development Goose Lake to Peigan to North Lethbridge and various 138 kV system reinforcements
Several other Southeast and Calgary area 2008-2011 $167 projects in 138 kV and 240 kV upgrades South region
central Several 138 kV system upgrades and 2008-2009 $121 projects interconnection of pipeline loads
Edmonton Several 240 kV and 138 kV upgrades; 2008-2010 $152 projects two 240 kV substations; 1202L conversion to 500 kV
northwest Northwest A single 240 kV line between 2010 $208 Alberta Brintnell and Wesley Creek transmission development
Northwest New 240 kV line, 144 kV line, Near $479 area new synchronous condenser, completion upgrades new SVCs, capacity bank and tele-protection upgrades
total $1,281
table 4.6.3-2: cancelled projects from the 2009 ltP
cost in 2009 ltP region Project description (2008 $ millions)
Edmonton Heartland Rebuild older 240 kV lines in the north $23 Area Edmonton area
Upgrade conductor on an 18 km section of the $4 existing double circuit 240 kV line in the north Edmonton area
renewable Northeast A new HVDC line or equivalent from the Fort $1,400 Slave River McMurray area to the Slave River hydro plant site hydro
Northwest Two new 500 kV AC lines from the Wabamun $500 Lake area to the Northwest region
total $1,927
table 4.6.3-3: Projects from the 2009 ltP delayed post 2020
Estimated cost in 2009 ltP Project in-service date (2008 $ millions)
CTI: East Fort McMurray 500 kV 2021-2022 $820
CTI: Increase capacity of both 500 kV HVDC lines Post 2020 $700
total $1,520
PagE 137
AESO Long-term Transmission Plan
table 4.6.3-5: new projects in this ltP
Estimated cost region Project description iSd driver (2011 $ millions)
South Fidler Fidler 240 kV substation 2012 Reliability and wind $35
Airdrie 240 kV and 138 kV enhancements 2015 Load and reliability $28
North Calgary – Local area 138 kV enhancements Load, aging $150 stage 1 and 69 kV conversion 2015 infrastructure, reliability
central Hanna 69 kV Convert local area transmission from 2018 Aging $66 69 kV to 138 kV infrastructure and load
Edmonton Garneau Upgrade the 72 kV network in 2013 Aging $150 Garneau/Meadowlark area infrastructure and reliability
Onoway upgrade Add reactive support 2013 Load $3
Extend KEG 500 kV interconnection to Sundance 2015-2017 Generation $119 500 kV interconnection
northeast Athabasca Upgrade telecom in area 2011 Reliability $20 telecom and operations upgrade
9L66 240 kV line 9L66 240 kV line relocation 2012 Load $1
Northeast Capacity banks at various substations 2012 Reliability $16 reactive power reinforcement
Fort Saskatchewan 240 kV enhancements 2013 Reliability $6 (near-term)
Algar substation New 240/138 kV substation at Algar 2015 Load $26
9L30 in/out at Terminate 9L30 (Whitefish-Leismer) 2015 Reliability $8 Heart Lake in/out at Heart Lake
Re-terminate Re-terminate east end of 9L15 2017 Reliability and load $40 east end of 9L15 (Brintnell-Wesley Creek) 240 kV line from Brintnell to Livock
Algor-Kinosis 240 kV double circuit Algor-Kinosis 2020 Load $61
northwest Otauwau/ 144 kV line from Otauwau to Slave Lake 2014 Reliability $18 Slave Lake and transformer upgrade
Bickerdike to 240 kV double circuit from 2015 Reliability $205 Little Smoky Bickerdike to Little Smoky
Hotchkiss Reactor banks addition 2015 Reliability $6 reactor banks
Milner 240 kV 240 kV double circuit from Milner 2015-2018 Generation $164 interconnection to new Wembley substation interconnection near Grande Prairie
total $1,122
4.0 AESO Analysis and Planning Results
PagE 138
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4.0 AESO Analysis and Planning Results
table 4.6.3-6: Projects in the 2009 ltP with scope changes included in this ltP
adjusted cost for Estimated cost project in 2009 ltP of this ltP region Project (2011 $ millions) (2011 $ millions)
cti East HVDC (CTI) $1,462 $1,622
Heartland 500 kV (CTI) $495 $537
South Calgary source (CTI) $112 $37
West Fort McMurray 500 kV (CTI) $1,378 $1,649
West HVDC (CTI) $1,277 $1,329
northwest Grande Prairie $193 $287
North Central $56 $65
Distribution points of delivery $0 $100
northeast Athabasca $38 $124
Christina Lake $253 $350
Heartland 240 kV second loop $247 $69
Livock $22 $24
Livock – Joslyn 240 kV $157 $342
North of Fort McMurray $354 $197
Salt Creek $34 $30
Thickwood $0 $173
Distribution points of delivery $112 $100
Edmonton North Edmonton $62 $34
South of Edmonton $54 $57
Southwest Edmonton $56 $95
Wabamun – Edmonton debottleneck $137 $153
Distribution points of delivery $169 $100
central Central East $359 $352
Hanna Area Transmission Development (HATD) $564 $909
Red Deer area $92 $204
Yellowhead $88 $123
Distribution points of delivery $94 $100
South Big Rock $57 $24
Calgary downtown cable replacement $22 $66
Calgary South 69 kV conversion $25 $23
Foothills Area Transmission Development (FATD) $619 $711
South Alberta 69 kV conversion $147 $48
South Area Transmission Reinforcement (SATR) $2,142 $2,287
Distribution points of delivery $70 $100
totals $10,951 $12,423
net difference $1,473
PagE 139
5.0Conclusion
This Long-term Transmission Plan (filed June 2012) presents an integrated, comprehensive
and strategic upgrade of the transmission system that meets statutory requirements, aligns
with public policy and strategy respecting electricity, meets load growth, and facilitates
development of Alberta’s abundant natural resources for the next 20 years. This Plan is
robust and flexible, and will be updated again in two years to report on changes in business
and economic conditions and incorporate any required amendments in the next LTP. This LTP
provides efficient, reliable, cost effective solutions to Alberta’s electric transmission system
and facilitates non-discriminatory system access service to customers by timely
implementation of transmission system enhancements.
The T-Reg directs the AESO to be proactive in its planning and development of the
transmission system since market signals alone do not provide timely indicators for
transmission development given the long lead time associated with these projects. While
this LTP is robust and flexible, there are implementation challenges. These challenges range
from environmental considerations and regulatory delays to cost and availability of labour
and materials. The AESO will respond to these challenges by establishing milestones where
appropriate, incorporating project staging, continued stakeholder consultation, facilitating
efficient regulatory coordination and filing and developing competitive procurement of
equipment and services. This allows consumers to receive maximum value from transmission
investments by timing the construction phases of projects to align with investment and
scheduled need dates.
This Plan introduces a supplement that will be updated every six months to track and
publish project updates, plus any material changes to the forecast, including refined project
cost estimates. The AESO’s objective is to continue to evolve the LTP content to include
information on additional and integral non-wires elements thereby increasing the value
to stakeholders and the comprehensive and transparent nature of the LTP.
5.0 Conclusion
PagE 140
AESO Long-term Transmission Plan
5.0 Conclusion
AES
O fi
le p
hoto
grap
h.
The AESO will continue to monitor key economic indicators, changes to legislation or
the regulatory framework, respond to customer requests for both load and generation
connections and evaluate the requirements for upgrading the transmission system.
Stakeholder engagement will remain an essential component in preparing the next
iteration of the LTP. Engagement with the public and with industry will continue, furthering
the objectives related to establishing CTI milestones, initiating a competitive process for
future transmission projects and determining intertie strategies.
This LTP process will serve to provide Albertans with continuing access to safe, reliable
and affordable electric power. Alberta’s future prosperity will be facilitated by having a
reliable transmission system, adequate generation resources, timely investment in
infrastructure and a competitive electricity market to benefit all Albertans.