AESO Long-term Transmission Plan€¦ · AESO Long-term Transmission Plan FILED JUNE 2012. Table of...

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


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


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



4.5.2.3 Northeast region transmission projects 112


4.5.3 Edmonton region 114



4.5.3.3 Edmonton region transmission projects 118


4.5.4 Central region 120



4.5.4.3 Central region transmission projects 123


4.5.5 South region 124



4.5.5.3 South region transmission projects 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


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


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


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.

PagE 4


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


Executive Summary

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

$120

$100

$80

$60

$40

$20

$0

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ill ($

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Energy, distribution and retail Transmission

$9/month $21/month

Ave

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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


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


Executive Summary

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12,000

10,000

8,000

6,000

4,000

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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


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


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


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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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


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


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

PAGE 16


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


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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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

PagE 20


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

PagE 21


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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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

PAGE 24


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

$900

$800

$700

$600

$500

$400

$300

$200

$100

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1,000

800

600

400

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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


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

PagE 26


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

PagE 29

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

PagE 30


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.


PagE 31


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.


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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


PagE 33


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.


PagE 34


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.


PagE 35


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


PagE 36


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


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


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)


PagE 38



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


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


PagE 40


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.


PagE 41


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.


PagE 42


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.


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PagE 43


South

Northwest Northeast

Edmonton

Central

Figure 3.5-1: transmission planning regions


PagE 44



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



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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



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


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.


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PagE 48


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.


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PagE 49


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.


PagE 50


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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PagE 51


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.


PagE 52


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.


PagE 53


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.


PagE 54


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.


PagE 56


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.


PagE 57


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

8,50

0

8,60

0

8,70

0

8,80

0

8,90

0

9,00

0

9,10

0

9,20

0

9,30

0

9,40

0

9,50

0

9,60

0

9,70

0

9,80

0

9,90

0

10,0

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


PagE 59


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.


PagE 60


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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4.0AESO Analysis and Planning Results

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.

4.0 AESO Analysis and Planning Results

PagE 62


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

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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


PagE 64


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


PagE 65


13,000

12,000

11,000

10,000

9,000

8,000

7,000

6,000

Ave

rage

hou

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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


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.

PagE 66


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


PagE 67


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.


PagE 68


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

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ate

Population growth

Figure 4.2.4-1: Comparison of inputs used for GDP growth, population growth,and oilsands production growth and latest updates


PagE 69


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).


PagE 70


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.


PagE 71


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


PagE 72


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.


AES

O fi

le p

hoto

grap

h.

PagE 73


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.


PagE 74


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


PagE 75


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


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.

PagE 76


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.


PagE 77


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


PagE 78


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.


PagE 79


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.


PagE 80


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.


PagE 81


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.


PagE 82


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.


PagE 83



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

PagE 84



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

PagE 85


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.


PagE 86



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

PagE 89


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

PagE 91


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

PagE 93


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

PagE 95


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


PagE 96



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.

PagE 97


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.


PagE 98



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.

PagE 99



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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.

PagE 100



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


69 kV/72 kV

138 kV/144 kV

240 kV


northwest

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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PagE 107


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.


PagE 108



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).

PagE 109


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


69 kV/72 kV

138 kV/144 kV

240 kV


northeast


generation (MW) Current installed 3,001 2020 forecast installed 4,865

PagE 110


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.


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.


PagE 111


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.


PagE 112


4.5.2.3 Northeast region transmission projects

table 4.5.2.3-1: northeast region transmission projects


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


total $1,547


PagE 113



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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PagE 114


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.


PagE 115


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


69 kV/72 kV

138 kV/144 kV 500 kV

240 kV


Edmonton


generation (MW) Current installed 4,457 2020 forecast installed 4,385 – 5,420

PagE 116


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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PagE 117



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.


PagE 118


4.5.3.3 Edmonton region transmission projects

table 4.5.3.3-1: Edmonton region current transmission projects


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


total $711


PagE 119



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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PagE 120


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.


PagE 121


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


69 kV/72 kV

138 kV/144 kV

240 kV


central


generation (MW) Current installed 1,837 2020 forecast installed 2,130 – 2,630

PagE 122


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.


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.


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.


PagE 123



4.5.4.3 Central region transmission projects

table 4.5.4.3-1: central region current transmission projects


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


total $1,754


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.

PagE 124


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.


PagE 125


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


69 kV/72 kV

138 kV/144 kV 500 kV

240 kV


South


generation (MW) Current installed 2,919 2020 forecast Installed 4,955 – 6,000

PagE 126



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.


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.

PagE 127




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


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


total $475


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.

PagE 128



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



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.

PagE 130


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 –


PagE 131


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


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


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


South region projects subtotal – $475 –

total, all projects 2011-2020 $13,545 –

Note: Totals and subtotals may differ due to rounding


PagE 132



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.

PagE 133



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



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


$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.


PagE 136



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


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


PagE 138



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


Edmonton North Edmonton $62 $34

South of Edmonton $54 $57

Southwest Edmonton $56 $95

Wabamun – Edmonton debottleneck $137 $153


central Central East $359 $352

Hanna Area Transmission Development (HATD) $564 $909

Red Deer area $92 $204

Yellowhead $88 $123


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


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


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.

Date post:	03-Oct-2020
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