AESO Long-term Transmission Plan

FILED JUNE 2012 Table of Contents

Executive Summary 1

1.0 Introduction 13

2.0 Background 15

2.1 Role of the AESO 15

2.2 Value of transmission 20

2.3 Planning for uncertainty 25

2.4 Transmission planning scenarios and sensitivities 27

3.0 aESO Planning Process 29

3.1 Stakeholder consultation process 30

3.2 Determining need 33

3.3 Load forecast process 35

3.4 Generation forecast process 39

3.5 System planning and reliability standards 42

3.6 Additional key considerations 47

3.6.1 Interties 47

3.6.2 Transmission technologies 49

3.6.3 Environmental considerations 51

3.6.4 AESO system operations 51

3.6.5 Ancillary services 52

3.6.6 Market evolution 55

3.6.7 Transmission Constraints Management (TCM) 56

3.6.7.1 Impact of transmission constraints on the wholesale electricity market 58

3.6.8 Telecommunications 59

Table of Contents AESO Long-term Transmission Plan

4.0 aESO Analysis and Planning Results 61

4.1 Overview 61

4.2 Load forecast – Future Demand and Energy Outlook (2009-2029) 61

4.2.1 Overview 61

4.2.2 Summary of key inputs 62

4.2.3 Anticipated trends 66

4.2.4 Uncertainties and concerns looking forward 67

4.3 Generation forecast 69

4.3.1 Gas-fired generation 71

4.3.2 Coal 72

4.3.3 Wind 72

4.3.4 Other renewable projects and new technologies 73

4.3.5 Large projects 73

4.3.6 Baseline generation scenarios 73

4.4 Bulk transmission system including CTI 76

4.4.1 Overview 76

4.4.2 Transmission technology alternatives 78

4.4.3 Project status 79

4.4.3.1 Edmonton to Calgary transmission system reinforcement 79

4.4.3.2 Heartland transmission system reinforcement 82

4.4.3.3 Fort McMurray transmission system reinforcements 85

4.4.3.4 Southern Alberta Transmission Reinforcement (SATR) 86

4.4.3.5 Foothills Area Transmission Development (FATD) 89

4.4.3.6 South Calgary transmission system reinforcements 91

4.4.3.7 Northwest transmission system reinforcements 93

4.4.4 Bulk projects cost estimates and timelines 95

4.4.5 Unique considerations and uncertainties on the bulk system 96

4.4.6 Bulk transmission system post-2020 99

Table of Contents AESO Long-term Transmission Plan

4.5 regional transmission system projects 102

4.5.1 Northwest region 102

4.5.1.1 Overview 102

4.5.1.2 Status of projects 105

4.5.1.3 Unique challenges, uncertainties and concerns 107

4.5.2 Northeast region 108

4.5.2.1 Overview 108

4.5.2.2 Status of projects 110

4.5.2.3 Northeast region transmission projects 112

4.5.2.4 Unique challenges, uncertainties and concerns 113

4.5.3 Edmonton region 114

4.5.3.1 Overview 114

4.5.3.2 Status of projects 117

4.5.3.3 Edmonton region transmission projects 118

4.5.3.4 Unique challenges, uncertainties and concerns 119

4.5.4 Central region 120

4.5.4.1 Overview 120

4.5.4.2 Status of projects 122

4.5.4.3 Central region transmission projects 123

4.5.4.4 Unique challenges, uncertainties and concerns 123

4.5.5 South region 124

4.5.5.1 Overview 124

4.5.5.2 Status of projects 126

4.5.5.3 South region transmission projects 127

4.5.5.4 Unique challenges, uncertainties and concerns 127

4.6 Long-term Transmission Plan costs 128

4.6.1 Project cost estimates 129

4.6.2 Transmission rate impact 132

4.6.3 Reconciliation of costs 135

5.0 Conclusion 139

Table of Contents AESO Long-term Transmission Plan

Appendices 141

Appendix A Glossary of Terms 141

Appendix B 24-Month Reliability Outlook (2010 – 2012) 151

Appendix C 2010 Annual Market Statistics 179

Appendix D Part 1 – FC2009 Overlay 207

Appendix D Part 2 – Future Demand and Energy Outlook (2009 – 2029) 219

Appendix E Generation Outlook 2009 – 2029 283

Appendix F Interties 323

Appendix G Advancements in Transmission Technology 337

Appendix H Ancillary Services Participant Manual 349

Appendix I Alberta’s Wholesale Electricity Market Design 401

Appendix J 2011 Long-term Telecommunications Plan 415

Appendix K Part 1 – The Value of Transmission 439

Appendix K Part 2 – Impact of Transmission Constraints on the Wholesale Electricity Market 453

Table of Contents 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. Stock photograph.

1 See s. 10(1)(a) of the T-Reg for a full listing of requirements for the LTP.

Executive Summary PAGE 1 AESO Long-term Transmission Plan

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 2 Executive Summary AESO Long-term Transmission Plan

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 egionalr 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.

Executive Summary PAGE 3 AESO Long-term Transmission Plan

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.

Figure 1: Reconciliation of this LTP and 2009 LTP costs $16,000

$14,000 1,927 Scope change 1,473

$12,000 1,520 New 1,122 1,281 1,216 $10,000

$8,000 14,463 $ millions 13,545

$6,000 10,951

$4,000

$2,000

$0 2009 LTP Projects Projects Projects Escalation Adjusted New projects This LTP (2008 $) cancelled delayed completed 2008 to 2011 2009 LTP and scope (2011 $) (2008 $) beyond 2020 or near (2011 $) (2011 $) changes (2008 $) completion (2011 $) (2008 $)

2 These estimates hold other costs constant, and do not include increases due to escalation of those other costs.

PAGE 4 Executive Summary AESO Long-term Transmission Plan

Figure 2: Transmission cost impact on residential and industrial customers Residential $120

$100 $21/month Transmission $9/month

$80

$60

Energy, distribution and retail $40 Average residential bill ($/month) residential Average

$20

$0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Energy, distribution and retail Transmission

Industrial $120

$100

$35/MWh $80 Transmission $16/MWh

$60

$40 Energy Average industrial charges ($/MWh) industrial charges Average

$20

$0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Energy Transmission

Executive Summary PAGE 5 AESO Long-term Transmission Plan

Assumptions and Inputs The AESO continually works with customers and stakeholders to monitor changes to the key inputs to our forecast of both load and generation. This LTP embodies the practice of continuous improvement at the AESO. To be prudent, the Plan is designed to be comprehensive and flexible in order to reflect the complexities and dependencies of project development, and to accommodate the variability of industries and business cycles. It addresses intra-Alberta physical transmission construction and reliability standards, and defines the need for restoring Alberta’s intertie capacity, temporary non-wires solutions, ancillary service requirements, system operations protocols, telecommunications requirements and criteria for market sustainability.

With each update, the Long-term Transmission Plan considers a variety of scenarios to help forecast future demand for electricity and the anticipated generation development to meet that demand. It also identifies a number of transmission scenarios which ultimately establish the need for transmission projects, projected in-service dates and estimated costs. Transmission investment is needed to reliably and efficiently serve expanding demand, reduce transmission congestion (and related congestion costs) and facilitate a competitive market.

The AESO has updated load and generation forecasts using third party experts such as The Conference Board of Canada, the Canadian Association of Petroleum Producers, and IHS Global Insights, as well as updated customer connection requests. Of note, the AESO is currently managing over 200 connection requests for load and generation facilities. The forecasts are consistent with the Alberta economic outlook. Stock photograph.

PAGE 6 Executive Summary AESO Long-term Transmission Plan

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.

Figure 3: Historical actual and current load forecasts 14,000

12,000

10,000

8,000

6,000 Average hourly AIL (MW) Average 4,000

2,000

0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Actuals Current forecast

Executive Summary PAGE 7 AESO Long-term Transmission Plan

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.

Figure 4: Generation mix: current and 2020 baseline

Current installed capacity 2020

44% Coal 5,782 MW 29% Coal 5,588 MW 41% Gas 5,371 MW 50% Gas 9,634 MW 7% Hydro 879 MW 5% Hydro 981 MW 6% Wind 777 MW 13% Wind 2,500 MW 2% Other 203 MW 2% Other 395 MW

PAGE 8 Executive Summary AESO Long-term Transmission Plan

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.

Executive Summary PAGE 9 AESO Long-term Transmission Plan

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. AESO file photograph.

PAGE 10 Executive Summary AESO Long-term Transmission Plan

Figure 5: Bulk system projects

Fort McMurray Area

3 3 Northwestern Area

Heartland Area 2

Wabamun Lake/ Edmonton Area

1 Thermal generator 1 Hydro plant Calgary HVDC converter Area Existing 240 kV Existing 500 kV Proposed 240 kV AC 4 Proposed 500 kV AC Proposed HVDC Existing substations HVDC: high voltage direct current Southern Hubs kV: kilovolt Area AC: alternating current

Critical Transmission Infrastructure Projects (CTI) 1 Edmonton-Calgary 3 Fort McMurray 500 kV 2 Heartland 4 South Calgary substation

Note: For illustrative purposes only; does not depict actual line routes or substation locations.

Executive Summary PAGE 11 AESO Long-term Transmission Plan

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 12 Executive Summary 1.0 Introduction

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. AESO file photograph.

1.0 Introduction PAGE 13 AESO Long-term Transmission Plan

The AESO uses this information to identify the best solutions to strengthen the electricity grid. The LTP is flexible and is based on information available today regarding assumptions of future conditions and circumstances. The AESO periodically reviews inputs to the LTP to determine if circumstances warrant a significant change in the approach. Should new information become available, the LTP is updated accordingly. An updated version is required to be filed with the Alberta Utilities Commission (AUC) and the Minister of Energy at least every two years, copies of which are available to the public.

This LTP takes a comprehensive and cost-effective approach to planning a strong transmission system so all Albertans can continue to depend on safe and reliable electricity. At the same time, this approach provides confidence for all power generators, including those who want to build more renewable and low-emission power generating facilities. It also provides confidence to investors in industry and business that the reliable, competitive electricity they depend on will be available to support their future plans.

To anticipate what is needed, the AESO considers a range of factors including Alberta’s economic outlook. The AESO planning team, including engineers, economists and transmission system planners, analyzes electricity consumption patterns in every area of the province and integrates data from many sources to determine where electricity demand will grow, where generation is or may be planned to meet that demand, and what additional transmission infrastructure is needed. The AESO also researches historical energy intensities for the industrial, oilsands, residential, farm and commercial sectors to adjust for future load patterns. In addition, a growing focus on customer consultation helps the AESO incorporate the most current information in estimating overall system needs. This includes ongoing research into oilsands recovery, industrial processes and cogeneration requirements and other end-use studies.

The projects identified in this LTP will not only help deliver the power Albertans need and facilitate the reliability of the provincial transmission system, but will also increase the efficiency of the transmission system. At the same time, transmission projects will remove existing geographic constraints on generation of all forms, including renewable sources such as wind, hydro and biomass. This will ensure electricity can move from where it is produced to where Albertans need it.

The following sections of the LTP provide background, set the context, explain the planning process, provide updates to the projects identified in the 2009 Long-term Transmission System Plan (2009 LTP), including those subsequently designated as Critical Transmission Infrastructure (CTI) and bulk and regional projects, and provide information on additional elements directly linked to maintaining a safe, reliable and secure transmission system.

The AESO is obligated to act in the public interest in developing the LTP. Government policy is also a key consideration in developing the Plan and should government policy change, the AESO would need to reflect those changes, reviewing and modifying the Plan accordingly.

PAGE 14 1.0 Introduction 2.0 Background

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 15 AESO Long-term Transmission Plan

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. AESO file photograph.

1 See s. 10(1)(a) of the T-Reg for a full listing of requirements for the LTP.

PAGE 16 2.0 Background AESO Long-term Transmission Plan

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 17 AESO Long-term Transmission Plan

The 2009 LTP identified transmission infrastructure essential to the long-term reliability and sustainability of the provincial grid. The subsequently defined Critical Transmission Infrastructure (CTI) projects are imperative to relieve congestion, provide connections to the major transmission hubs in Alberta, connect regional loads and generation, reduce transmission system losses and support long-term economic investment and growth. The development of CTI projects in a proactive fashion removes investment uncertainty around transmission access for both generation and load and supports an uncongested, competitive market. Bulk system expansion is also required to link regional developments and support continued economic growth in Alberta.

Although this LTP provides a 20-year assessment, to comply with Alberta Reliability Standards the AESO must demonstrate the transmission system is planned in the 10-year horizon such that:

n It can be operated to accommodate forecast load and generation scenarios without interruptions when all transmission facilities are in service (TPL-001).

n It can be operated to accommodate forecast load and generation without interruptions following the loss of a single element (TPL-002).

n When system simulations indicate an inability to meet the above requirements, the AESO must develop transmission enhancements to achieve the required performance (TPL-001 and TPL-002).

n It can be operated to accommodate forecast load with controlled load interruption or removal of generation following the loss of two or more elements (TPL-003).

n It has been evaluated for the risks of extreme events (TPL-004).

The AESO operates the AIES to stay within acceptable limits during normal conditions, to perform acceptably after credible contingencies, to limit the impact and scope of instability and cascading outages when they occur, to ensure facilities are protected from unacceptable damage by operating them within facility ratings, and to restore system integrity promptly if it is lost. The system must supply the aggregate electric power and energy requirements of electricity consumers, taking into account scheduled and reasonably expected unscheduled outages of system components. These criteria define how the system is planned to operate reliably and safely.

The LTP must also address criteria outlined in regulations related to telecommunications and certain market and operational products and services (i.e., ancillary service (AS), transmission must-run (TMR), transmission congestion management (TCM), etc.) used to directly support the safe, reliable and efficient operation of the transmission system.

PAGE 18 2.0 Background AESO Long-term Transmission Plan

Section 1 of the EUA defines transmission facilities and transmission system to include telecommunications as follows:

bbb) “transmission facility” means an arrangement of conductors and transformation equipment that transmits electricity from the high voltage terminal of the generation transformer to the low voltage terminal of the step down transformer operating phase to phase at a nominal high voltage level of more than 25,000 volts to a nominal low voltage level of 25,000 volts or less, and includes: (i) transmission lines energized in excess of 25,000 volts, (ii) insulating and supporting structures, (iii) substations, transformers and switchgear, (iv) operational, telecommunication and control devices, (v) all property of any kind used for the purpose of, or in connection with, the operation of the transmission facility, including all equipment in a substation used to transmit electric energy from... ccc) “transmission system” means all transmission facilities that are part of the interconnected electric system.

In order to capture and respond to changing system conditions, the AESO collects information and evaluates need over three key periods: (1) over the short term or two years, typically focused on regional needs; (2) over a 10-year horizon identifying medium-term needs, addressing both bulk system and regional projects; and (3) up to a 20-year timeline indicating long-term developments, typically aimed at the bulk system enhancements. The transmission planning process involves frequently evaluating changes to the system that are required at the regional, bulk and interconnected levels in response to changes in information.

Figure 1: Long-term plan process

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2.0 Background PAGE 19 AESO Long-term Transmission Plan

2.2 Value of Transmission The AESO is charged with the responsibility for planning the transmission system to ensure adequate transmission capacity is in place in advance of need. In Alberta’s deregulated, single price, wholesale electricity market, this means that transmission plans must allow all generators to have equal opportunity to fully compete in the market and allow all loads to withdraw power whenever and wherever it is required. A lack of transmission capacity should neither hinder economic development decisions, nor determine winners or losers in the wholesale electricity market. Only an adequate, open, non-discriminatory transmission system can achieve these objectives.

Throughout North America, there are a number of electricity delivery models ranging from localized delivery systems within a municipal service territory or industrial system to fully integrated grids over large balancing authorities. While localized delivery systems may offer efficiencies due to integrated systems and balances of load and generation, there are greater economies of scale available in larger market systems. Transmission is critical to securing the benefits of large-scale integrated grid models. While some may argue that distributed generation can provide an alternative solution to large-scale generation, this is refuted by two main points: (1) transmission is the low-cost element in the total cost of electricity, supporting a competitive generation network, and (2) generation at the local, or any level, cannot be a full substitute for transmission because it is less available, and therefore less reliable, and can lead to issues of local market power.

The value of transmission is measured in comparison to the value of economic development that it supports and also in comparison to the next alternative.

The economy of Alberta, as measured by Gross Domestic Product (GDP), is expected to grow strongly over the next decade. The investment and development associated with this economic growth is dependent upon having a reliable transmission system that can serve the needs of growing businesses and industries. Investors assume adequate transmission capacity will be available to accommodate their plans for development.

The Conference Board of Canada estimates that Alberta GDP in 2014 will be $396 billion (2014 dollars). This strong GDP growth translates to a significant capital investment in Alberta that provides both direct and indirect benefits to Albertans through employment, services, tax revenues, and resource rents (royalties). As Table 2.2-1 illustrates, over $180 billion of investment has been identified across multiple sectors for projects that have recently been completed, are currently under construction, or are proposed to start construction within the next two years.

PAGE 20 2.0 Background AESO Long-term Transmission Plan

Table 2.2-1: Alberta Finance and Enterprise inventory of major projects (April 2011) valued at $5 million or greater

N 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 Stock photograph.

2.0 Background PAGE 21 AESO Long-term Transmission Plan

The transmission development recommendations in this LTP address a 20-year horizon and leverage the economies of scale of building large-scale transmission now to support the system today and into the future. There are significant economic and regulatory efficiencies to be gained from sizing facilities for anticipated demand 20 to 30 years into the future. This approach avoids having to repeatedly expand existing transmission corridors or create new corridors to add small incremental capacity to the system to meet demand growth over time.

Building in advance of need leverages the economies of scale that recognizes transmission infrastructure has an investment lifespan of more than 40 years.

Transmission value is created by investing in backbone infrastructure today that is designed to link regional hubs, relieve congestion, satisfy operational and reliability objectives internally and across other balancing authorities, and support large-scale growth in the province.

The CTI projects are consistent with a value assessment that recognizes the benefits of infrastructure designed to reduce congestion and to support large-scale growth in Alberta over a long-term horizon.

As Alberta grows and develops its vast bounty of natural resources, demand will increase significantly and the transmission system must evolve in anticipation of this demand. Moving from a 240 kV system to a 500 kV backbone as new upgrades are built will provide significant near-term benefits by alleviating transmission congestion and will enable efficient system operation for decades to come and allow Alberta to keep pace with world demand for its resources. AESO file photograph.

PAGE 22 2.0 Background AESO Long-term Transmission Plan

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 23 AESO Long-term Transmission Plan

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.

Figure 2.2-1: Actual and estimated cost of transmission congestion events equivalent to those observed from 2008 to 2010 $1,000 1,200

$900 1,000 $800

$700 800 $600

$500 600

$400 400 $300

$200 of transmission congestion (GWh) Volume Cost of transmission congestion ($ millions) 200 $100

$0 2008 2009 2010 0

Estimated cost of constrained down generation ($ millions) Volume of transmission must-run (GWh) Cost of transmission must-run ($ millions) Volume of constrained down generation (GWh)

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.

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 24 2.0 Background AESO Long-term Transmission Plan

2.3 Planning for Uncertainty Long-term transmission planning is inherently uncertain given the time horizons involved, the diversity of generation that may or may not be built, the importance of locational siting and the critical importance of timing. Transmission investment decisions must anticipate need decades into the future because transmission infrastructure has an investment lifespan of 30 to 40 years and new developments require five to eight years to plan and build. In addition to reliability requirements, transmission plans must consider trends in economic development, population growth, technological advancement and environmental regulation, as well as trends in neighbouring jurisdictions in order to arrive at robust solutions that stand the test of time. Given the large number of variables involved, accurate and complete forecasting of load and generation growth over the long economic life of transmission assets is difficult. Decisions must be made through the use of scenario analysis to arrive at plans that can adapt to a broad range of potential future outcomes. This is also why the planning process needs to be reviewed and updated on a regular basis.

Prior to deregulation, integrated utilities planned both generation and transmission development to meet anticipated demand. While there was significant long-term uncertainty associated with the timing and location of new load, the timing and location of new generation was under the control of the utility system planners. In Alberta’s deregulated market, transmission planning is characterized by additional uncertainty because the timing and location of new generation additions and retirements are private investment decisions made independently of the AESO.

With the large number of variables that must be considered, the AESO’s transmission plans must be robust and flexible so that the configuration of the system does not constrain future economic development. In recognition of this uncertainty, the 2003 Transmission Development Policy (Transmission Policy) provides direction to the AESO to be proactive in its planning and build transmission in advance of need since market signals will not provide timely indicators for development given the long lead time associated with transmission projects. The use of project staging enables prudent timing of transmission developments ensuring consumers receive maximum value from transmission investments by timing the construction of incremental phases of projects to align investment with anticipated need dates.

2.0 Background PAGE 25 AESO Long-term Transmission Plan

As policies evolve and fuel source preferences change over time, adequate transmission capacity facilitates changes in the generation fleet as investors and generation developers choose new types and locations of generation based on the availability of new fuels. Wind and hydro power provide low cost, carbon free energy that complements thermal sources such as natural gas and coal. A diverse mix of generation sources provides economic and environmental benefits which is a key objective of the Transmission Policy and, subsequently, transmission planning.

The long lead time and economic life associated with transmission projects results in an asymmetric risk profile for transmission development – the cost of building insufficient transmission capacity far outweighs the cost of building excess transmission capacity.

If forecasts for load and generation evolve more slowly, the AESO believes it is a reasonable assumption that loads and generation will only be delayed, eventually catching up to where the transmission can be fully utilized.

If future expectations of need turn out to have underestimated the amount of transmission capacity required, the consequences are much greater. Economic development may be deferred or reduced due to the lack of sufficient transmission capacity. Increased congestion will undermine the efficiency of the wholesale market, increasing the delivered cost of power to consumers, reducing the competitiveness of generators and potentially discourage the entry of new market participants. System inefficiency will intensify with increased line loading, which will result in greater losses and expanded reliance on non-wires solutions such as TMR to compensate for inadequate transmission capacity in constrained areas. The sum of these consequences is far greater than the fixed cost associated with building excess transmission capacity to meet future anticipated needs with the ultimate penalty being reduced system reliability.

In determining the appropriate size of incremental transmission additions, the most effective hedge against future uncertainty is to plan for the most likely demand and generation growth scenarios to ensure sufficient capacity margin and minimize the significant consequences associated with insufficient transmission capacity. The AESO takes a measured approach to determine solutions that are practical, prudent and cost effective. Consideration for staging projects and defining milestones are employed where appropriate. This follows the direction of the current T-Reg, Part 3, Transmission System Criteria and Reliability Standards.

PAGE 26 2.0 Background AESO Long-term Transmission Plan

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. Photo courtesy of AltaLink.

2.0 Background PAGE 27 AESO Long-term Transmission Plan

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.

PAGE 28 2.0 Background 3.0 AESO 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 29 AESO Long-term Transmission Plan

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 30 3.0 AESO Planning Process AESO Long-term Transmission Plan

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. Stock photograph.

3.0 AESO Planning Process PAGE 31 AESO Long-term Transmission Plan

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 edition distributed – Distributed at 12 open houses – Over 120 copies distributed to schools and libraries

Presentations and 64 84 discussions with municipalities

PagE 32 3.0 AESO Planning Process AESO Long-term Transmission Plan

3.2 Determining Need Since release of the 2009 LTP, Alberta has experienced significant changes to the economy including broadly fluctuating commodity prices, availability of credit, changes to environmental policy and generation announcements.

Despite the economic slowdown, economic fundamentals remain strong for Alberta and show a long-term growth in demand of 3.2 per cent annually for the next 20 years. The economic recovery in Alberta continues as confidence in all sectors appears to be strong. The key driver of the Alberta economy continues to be expected investment in oilsands, which relies on the availability of significant electrical infrastructure. In addition, with the expected retirement of coal-fired generation, the need for transmission remains to support the replacement of this retiring generation and anticipated additional or replacement generation. This LTP contains many of the same assumptions outlined in the 2009 LTP, although some have changed to reflect policy and recent generation announcements:

n Historical system energy consumption grew from 38 terawatts (TWh) in 1990 to 72 TWh in 2010 (or 3.2 per cent average annual growth), and is expected to nearly double again by 2029 from 72 TWh in 2010 to 132 TWh in 2029.

n System demand for transmission remains regionally diverse.

n Recent climate change announcements by the federal government to stipulate a clean coal obligation change the outlook for coal and the likely increased reliance on gas as a fuel source for generation.

n Recent announcements by generators, specifically those with power purchase arrangements (PPA) in place, reflect the potential for early retirement of the coal-fired generators.

n Some changes in generation outlook are also noted including scenarios related to the timing of the Sundance 7 in-service date, recognition of the H.R. Milner expansion and the deferral of Slave River Hydro generation.

Transmission planning is an ongoing process intended to reflect changes in the economy, commodity prices, industrial projects, customer connection requests and generation development in determination of need. While the baseline forecast has been adjusted to accommodate these changes since the 2009 LTP, the fundamental need for transmission system developments and regional upgrades remains valid to replace aging infrastructure and resolve issues related to an increasingly constrained transmission grid.

3.0 AESO Planning Process PAGE 33 AESO Long-term Transmission Plan

The expected change in the diversity of the generation fleet over time will have some impact on future transmission planning as well. By 2020, the AESO expects total installed generation capacity to grow to approximately 19,000 megawatts (MW). Today’s supply is weighted towards a coal-fired and gas-fired mix. However, it is anticipated that with the retirement of coal at the later of PPA expiry or facility life (typically considered 45 years), natural gas-fired generation will be the fuel of choice to replace coal. Gas plants are an economically viable alternative and are useful in backing up the increasing amount of intermittent resources on the grid. As gas is more locationally flexible than some other fuel sources, the AESO will test its transmission plans using various locational options.

Despite changes to load and generation expectations, the key factors influencing this LTP include many of the same key components introduced in the 2009 LTP:

n Need for CTI to strengthen the backbone of the transmission system, resolve current operational limitations and support long-term provincial growth.

n Ongoing load growth despite recent short-term economic slowdown.

n Additional investment in generation continues, ranging from new wind facilities to the addition of new gas generation and future cogeneration operations. Recognition of the environmental policy pressure on coal to meet clean standards, which could drive the possibility of new gas-fired generation as a replacement.

n Further evaluation and assessment required of the criteria and future need determination for intertie development to support reliability, load and market objectives fulfilled by access to larger markets. This LTP reflects the current analysis underway related to integrating new merchant transmission onto the grid (i.e., Montana-Alberta Tie Line).

n Recognition of the supporting interim non-wires solutions, operational protocols and services in place to support transmission infrastructure, market dispatch and system reliability.

PAGE 34 3.0 AESO Planning Process AESO Long-term Transmission Plan

3.3 Load Forecast PROCESS Establishing a robust and credible Alberta load forecast is an essential first step in determining need for future transmission builds. The baseline load forecast used for this LTP was published in February 2010 and is referred to as the Future Demand and Energy Outlook (2009-2029) (FC2009). The FC2009 is reassessed as new information becomes available to ensure it remains valid and reasonable.

Key inputs into the Alberta Internal Load (AIL) energy and load forecast are Alberta gross domestic product (GDP), population growth, oilsands production, personal disposable income and detailed project and distribution facility owner future load information.

To get the most accurate information, the AESO relies on third-party experts such as The Conference Board of Canada, Canadian Association of Petroleum Producers and IHS Global Insight. These forecasts are cross-referenced for consistency and reasonableness.

The FC2009 forecast used econometric, top-down, and bottom-up models to forecast electricity usage on a customer sector basis. This methodology provides a consistent and balanced approach to load forecasting through the use of a combination of fitted statistical models, historical data, third-party economic forecasts and customer-specific information. The AESO’s models are consistent with industry standards for forecasting electricity demand and are customized to fit Alberta’s unique characteristics. A more detailed description of the load forecasting process can be found in Appendix D. Figure 3.3-1 provides an overview of the load forecast development process.

Figure 3.3-1: Load forecast development process

Residential, commercial, Economic variables Project specific farm, industrial and oilsands (GDP, population, etc.) information energy – 20 year forecast

Hourly load shape by 20-year hourly point of delivery (POD) forecast by POD

Regional, provincial Used in regional Input to generation Alberta internal studies and bulk scenarios/forecast load (AIL) forecast system studies

Onsite generation Alberta Interconnected Billing determinants forecast Electric System (AIES) (Tariff) load forecast, behind- the-fence (BTF) forecast

3.0 AESO Planning Process PAGE 35 AESO Long-term Transmission Plan

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.

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

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 36 3.0 AESO Planning Process AESO Long-term Transmission Plan

Oilsands: In 2010, this sector comprised 16 per cent of total AIL energy. The model relies on estimation from third parties of mining, in situ and upgrading production multiplied by an intensity factor for each process. The intensity factors assumed in the forecast are based on actual historical usage. The production forecast was based on the Canadian Association of Petroleum Producers’ June 2009 Outlook.

Commercial: This sector accounts for 19 per cent of total AIL energy and is a regression model using the historical relationship between commercial energy and Alberta GDP. The GDP forecast used was from The Conference Board of Canada.

Residential: This sector is around 13 per cent of total AIL energy and is a function of population and disposable income per person. Forecasts of population and disposable income per person are from The Conference Board of Canada.

Farm: This sector is the smallest sector at two per cent of the AIL. The AESO used a 10-year historical average annual energy calculation to forecast future electricity demand for this sector.

Losses: Includes distribution and transmission losses and energy to Fort Nelson, British Columbia through its connection to the AIES.

Figure 3.3-3: Historic annual AIL energy by sector, excluding losses (GWh) 70,000

60,000

50,000

40,000

30,000 Annual energy (GWh) Annual energy

20,000

10,000

0 1967 1969 1971 1973 1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009

Industrial (without oilsands) Commercial Oilsands Residential Farm

3.0 AESO Planning Process PAGE 37 AESO Long-term Transmission Plan

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.

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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.

Figure 3.4-1: Generation forecast development process

Available generation High level outlook of Project specific resources (technologies, generation development information resources, costs)

Annual generation 20-year load forecast capacity additions by location, type and size

Validate load adequacy and market signals with generation forecast

Onsite generation Used in regional Finalize generation forecast to studies and bulk forecast and scenarios load forecast system studies

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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 theequirement r 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.

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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.

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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. Photo courtesy of AltaLink.

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Figure 3.5-1: Transmission planning regions

Northwest Northeast

Edmonton

Central

South

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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).

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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. Stock photograph.

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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.

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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. Photo courtesy of ENMAX Energy.

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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. AESO file photograph.

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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.

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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. Stock photograph.

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3.6.3 Environmental considerations Environmental considerations are part of the LTP in two ways. First, the current and expected environmental policy directly influences the need for transmission by either supporting or discouraging the use of certain generation fuel sources. Second, environmental policies impact the location and type of electrical load that may develop and the related transmission need.

The AESO also considers environmental impact in choosing general transmission study areas and the technology to be employed. The assessment of environmental impact is specifically included as part of project NID filings which are evaluated in a hearing process in front of the AUC. The siting of final routes for CTI projects incorporates environmental considerations through the Facility Application process.

In all cases, transmission projects are evaluated after taking environmental impacts, among other factors, into consideration.

3.6.4 AESO system operations The AESO system controller function operates much like an air traffic controller, using sophisticated data capture and analysis tools to monitor, analyze and direct the safe and reliable operation of the AIES 24 hours a day, seven days a week. This is accomplished using control systems that provide real-time visibility of power grid conditions and allow for contingency analysis in the event of transmission system element failures.

In addition to balancing supply and demand in real time, the system controller is responsible for all outage coordination, short-term and long-term operational planning, and working collaboratively with transmission facility owners and Emergency Management Alberta on system restoration activities to ensure that in the event of a major disruption to service, normal operations can be quickly restored with minimal disruption to all Albertans.

Over the last decade, demands on the provincial transmission infrastructure have increased significantly due to the growth in system load and the expansion of generating facilities – facilities that are now more diverse in type and geographic location. The significant increase of wind production in the south of the province and cogeneration in the north creates unique operational challenges to the system. These types of generation facilities can be intermittent in nature and operate in a manner that is not highly controllable: wind power is generated when the wind blows and cogeneration facilities are designed and operated to meet industrial process needs rather than power system requirements. The variability of generation production has strained transmission operations over the past few years and will continue to do so until the bulk and regional transmission systems are expanded to better accommodate these types of generation sources.

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AESO operations manages the grid and system constraints through the effective execution of documented policies and procedures to ensure consistency and effective implementation of market rules. However, as the complexity and demand on the system increases, it has become evident that additional information systems and technologies are needed to ensure visibility and proactive mitigation of potential system overloads. The AESO began upgrading its Energy Management System in 2007 with stage one implemented in 2009. These upgrades will continue in phases over the next three to five years as the AESO integrates this new technology into daily operations.

The new Energy Management System provides greater situational awareness and contingency analysis options to system controllers and their support teams, allowing for transmission capacity to be maximized while maintaining a safe and reliable operating condition. Custom tools are being developed and implemented for the control room to monitor and manage the variability of wind resources within the province, allowing for the system to connect and absorb a greater volume of renewable resources than would otherwise have been possible.

Effective operation of the grid directly supports Alberta’s fair, efficient and openly competitive market structure. As the size and complexity of Alberta’s power system grows, AESO operations will continue to evolve and employ the most appropriate technologies in its drive to maintain a safe, reliable and efficient system.

3.6.5 Ancillary services The LTP considers the non-wires, interim and supplemental operational support required for the safe, reliable and efficient operation of the AIES and the fair, efficient, open and competitive operation of the market. These considerations are in addition to existing physical transmission plans. One of the critical considerations of a sustainable transmission plan is the need to minimize the cost of ancillary services by removing system constraints. Having said that, the AESO recognizes that as more variable wind resources are integrated into the system, the need for ancillary services will increase. The AESO is continuing to assess this requirement and will include the results of the analysis in future updates of the LTP.

With the current transmission system operating at or near its limit during peak conditions, until new transmission is built the system is reliant on operational tools and non-wires alternatives. For example, the system relies on transmission must-run (TMR) in the Rainbow Lake, northwest Alberta and Calgary areas to maintain system reliability and serve local loads that are isolated from the system. In addition, wind generation constraints occur in the Southwest region due to delayed reinforcement of transmission in that area. Additionally, several areas of Alberta experience generation or load constraints when transmission facilities are taken out of service, whether for planned maintenance or forced outages such as during lightening storms.

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When the system experiences constraints or operational disturbances, the AESO relies on the procurement of ancillary services and the development and implementation of operational procedure. The AESO also continues to rely on coordination of planned outages to minimize supply adequacy issues. System controller training and procedures are developed and implemented to support ongoing monitoring and response alternatives to challenging system conditions.

Ancillary services used to support reliability include:

n Transmission must-run service – supplied by a generator that is required to be online and operating at specific levels in parts of the system where local transmission capacity is insufficient to meet local demand.

n Operating reserve – available output from a generator that can be dispatched, or load that can be reduced, to maintain system reliability in the event of an imbalance between supply and demand on the electricity system. Operating reserve is further broken into regulating reserve and contingency reserve.

n Regulating reserve – available output from a generator that can be dispatched, and is responsive to automatic generation control, to provide the power needed to address the lag period between balancing supply and demand (as generators catch up to increasing or decreasing load) as well as for voltage support.

n Contingency reserve – available output from a generator that can be dispatched, or load that can be reduced, to restore the balance of supply and demand of electricity following a contingency or unforeseen event on the system. Contingency reserve is further broken into spinning (immediate generator response) and supplemental (10-minute response – generation and load) reserve.

n Black start service – supplied by generators that are able to restart their generation facility with no outside source of power. In the event of a system-wide blackout, black start providers are called upon to re-energize the transmission system by providing start-up power to generators who cannot self-start.

n Load shed scheme service – supplied by electricity consumers (load) who have agreed with the AESO to be automatically tripped off (curtailed) in order to instantly reduce demand in the event of an unexpected problem that threatens the balance of supply and demand of electricity on the system.

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In accordance with the Transmission Regulation, load customers pay for the costs of ancillary services, including operating reserve. The mechanism the AESO uses to recover these costs from load customers is the tariff, which is filed for approval with the AUC. In the AESO tariff, costs for ancillary services are identified in the rate component applicable to load customers and broken out in the following charges:

n The operating reserve charge recovers costs associated with regulating, spinning and supplemental reserve (both active and standby) and with some miscellaneous ancillary services where the cost varies with pool price.

n The voltage control charge recovers costs associated with the provision of transmission must-run services.

n The other system support services charge recovers costs associated with some miscellaneous ancillary services where the cost does not vary with pool price.

The operating reserve charge makes up the largest part of ancillary services costs recovered. The transmission must-run expense is the next largest expense and the other system support services charges represent the smallest charge.

The procurement and use of ancillary services will continue to be critical to ensuring the physical transmission system remains safe, reliable and able to respond to customer connection needs. By planning transmission infrastructure appropriately, the reliance on and need to procure large volumes of ancillary services will diminish over time. These services supplement the available capacity and operational protocols that are part of effectively operating the grid 24 hours a day, seven days a week. A more detailed discussion on ancillary services can be found in Appendix H. AESO file photograph.

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3.6.6 Market evolution As described throughout this LTP, Alberta’s electricity market provides choice to consumers and incents generators to build in Alberta and to import power into Alberta when needed by the transmission system. Transmission is required to serve both consumers and generators in the delivery of electricity and also to connect new and varying fuel types of generators wherever they decide to locate. Simply put, transmission development addresses both reliability and market objectives. As noted in Alberta government policy and confirmed by the T-Reg, an uncongested transmission system is critical to ensuring an effective and efficient electricity market for all.

As it is an iterative process – loads drive generation, which in turn drives transmission, which supports all customers – the market must continue to evolve to meet the needs of the system. This current LTP is based on assumptions that generation will be unencumbered allowing investment opportunities in new generation facilities. It is also based on assumptions related to market rules for various fuel types such as support for wind development and a framework for interties. Accordingly, the AESO continues to support market evolution to encourage generation and load development in the province.

The LTP relies on the market, working in consultation with the AESO, to address key design practices including:

n Integration of wind resources – procurement of new ancillary services products and rules for forecasting wind and power management.

n Creation of ancillary products to restore the capability of current interties to rated capacities and address system reliability.

n Development of demand participation products that, with smart grid technologies, may lead to efficiencies in demand requirements.

n Development of framework details for participation of interties in the Alberta market including tariff design, capacity allocation rules and design to consider integration of future interties including possible merchant lines.

n Implementation of congestion management rules and procedures for short-term constraints.

Each of these priorities is consistent with baseline assumptions built into the LTP and supports an evolving competitive market for electricity while responding to a growing economy. Appendix I provides more detail on the market evolution in Alberta.

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3.6.7 Transmission Constraints Management (TCM) The transmission system must be free of transmission constraints for the underlying market model to function effectively. Transmission constraints can interfere with the flow of electricity from one part of the system to another or alter the normal dispatch of the energy market merit order, restricting market participants’ access to the market and impacting market prices. Transmission policy must ensure transmission access and contribute to a stable investment climate in order to maintain investor confidence.

Alberta’s transmission system is currently running at capacity, which requires the AESO to actively manage constraints on transmission lines across the province. Until transmission upgrades are in service, the AESO will continue to take appropriate operational action to maintain system reliability, optimize the use of existing transmission and manage constraints.

The T-Reg provides for adequate transmission so that, on an annual basis, and at least 95 per cent of the time, transmission of all anticipated in-merit energy can occur when operating under abnormal operating conditions.

Reliability criteria are applied in planning studies to identify potential constraints and within system monitoring and control systems to provide warnings of real time potential or actual constraints. AESO monitoring and control systems detect constraints that the system controller must mitigate using established protocols and procedures.

The T-Reg requires the AESO to make rules and establish practices to manage transmission constraints that may arise from time to time. The AESO has been consulting on constraints management with industry since the T-Reg became law in 2004. During those discussions, the AESO has been guided by the principles and recommendations of both the 2004 Transmission Development Policy (TDP) and the 2005 Electricity Policy Framework.

The AESO has recently received confirmation from the AUC of Transmission Constraints Management Rule 9.4 (TCM Rule), a generic rule that will serve as a template for managing all transmission constraints, planned or unplanned. The TCM Rule is aligned with the TDP which requires the AESO to use reverse merit order and pro-rata curtailment to manage constraints. The TCM Rule also results in a minimal amount of price impact or distortion as mandated by the TDP. The TCM Rule incorporates procedures intended to minimize the impact of constraints on the energy market by curtailing ancillary services before energy and prevents constraints of longer duration from impacting market participants’ offer behaviour.

The TCM Rule will also guide the AESO’s development of Operating Policies and Procedures (OPPs). OPPs provide the system controller predetermined policies and procedures to apply in real time to address specific known constraints. These known constraints may have been identified in the planning stages of system development or in the nearer term operational environment when applying reliability criteria to the system as it exists at the time or as it will change in the very near term. Although guided by and aligned with the generic TCM Rule, the appropriate procedure required for a known constraint must be determined on a case- by-case basis and, when it becomes part of an OPP, is subject to stakeholder consultation.

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The AESO notes that transmission constraints impact the market supply and demand balance and the approved TCM protocol is expected to work effectively within the current market design to restore that balance while having a minimal impact on pool price.

The AESO currently manages, and will continue to manage congestion effectively by using practices and procedures such as the connection process, regional operating procedures and remedial action schemes. These measures optimize the use of the system and lead to less frequent and shorter duration congestion events. The AESO operates the system in a manner that ensures reliability criteria and reliability standards are met. The AESO notes that the amount of future regional congestion will grow and increase the generator and load restrictions associated with meeting the reliability criteria until planned regional transmission upgrades are in place. Until transmission upgrades are complete, the AESO expects congestion will be infrequent and of short duration using the proposed TCM Rules.

The AESO will continue to develop and implement Independent System Operator (ISO) Rules and operational procedures to manage constraints that have been identified in the planning stages of system development and operations. The ISO rules will be consulted on through the established rule consultation process as prescribed by the AUC. The transmission facilities required to alleviate constraints will be identified through the AESO’s connection process and the long-term planning process.

The AESO regularly monitors the impact of transmission constraints on the market and undertakes annual stakeholder reviews to discuss regional constraint issues. Please refer to the AESO’s 24-Month Reliability Outlook (Appendix B) for historical constraint information on our website. AESO file photograph.

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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.

Figure 3.6.7-1: Example of the impact constrained generation has on price $1,000

$900

$800

$700

$600

$500 $/MWh

Original price at 9,500 MW dispatch level: $400 $73.35/MWh Increased price at 9,500 MW dispatch $300 level (with 100 MW constraint applied): $494.70/MWh $200 Difference: $421.35/MWh

$100

$0 8,000 8,100 8,200 8,300 8,400 8,500 8,600 8,700 8,800 8,900 9,000 9,100 9,200 9,300 9,400 9,500 9,600 9,700 9,800 9,900 10,000 10,100 10,200 Actual merit order Merit order with a 100 MW constraint

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The use of TMR services also comes at an incremental cost to the system. In 2010 the actual cost for TMR was $26.1 million.

The impact of constrained generation on pool price varies with the offer curve, demand levels and other market fundamentals. It is estimated that for constraints similar to those observed in the past three years, pool prices are, on average, greater by $1.59/MWh for regular constraints and $8.02/MWh for constraints associated with major events compared to an unconstrained system.

In addition, over the past three years, the cost of TMR has averaged $0.58/MWh due to location specific constraints. These costs, the observed trend of increasing levels of constraint, and the currently forecasted increases in demand and generation levels indicate that there is significant value to incremental transmission capacity in Alberta. Alberta’s single price energy-only market design is predicated on an unconstrained transmission system.

3.6.8 Telecommunications The AIES utility telecommunications networks owned and operated by transmission facility owners are used for the transmission of teleprotection signals, operational data, SCADA data, and voice and mobile radio communications.

Section 10 of the T-Reg requires the AESO to prepare a long-term plan for the transmission system. The definitions included in the EUA imply that telecommunications system planning is included in the LTP.

The operation of the transmission system requires a functional and effective telecommunications network where the design and performance of the communications system will contribute to the ability of the system to meet Alberta Reliability Standards. As part of the LTP, the telecommunications plan provides a blueprint for how Alberta’s aging microwave telecommunication systems will be replaced and/or modified with more advanced and durable fibre optic technology. It should be noted that in certain areas of the province, the microwave system will continue to be used as it is more cost effective. Also of note is that each transmission project allows for between three to five per cent of the total cost for telecom upgrades specific to the project. No additional capital cost is anticipated to be incurred to implement this plan over the next decade. The general principles of the telecommunication plan are as follows:

n Operate the network with extremely high reliability.

n Support ongoing system growth including applications for smart grid in the future.

n Meet standards for low latency (for teleprotection) and high standards for network security.

n Minimize environmental impact.

n Meet total operational cost objectives.

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The major projects summarized in the Table 3.6.8-1 below represent the additional telecommunication projects required to support this LTP. Further details of the telecommunications plan are found in Appendix J.

Table 3.6.8-1: Major telecommunication network developments

Region/area Project Comments

Edmonton Keephills – Sundance – Optical ground wire (OPGW) installation to meet Genesee – Ellerslie – latency requirements for protection system Summerside North Calder – Poundmaker AESO to review specifications and include OPGW between 37S North Calder and Poundmaker

Red Deer 17S Benalto – 63S Red Deer Inclusion of OPGW on rebuild of the 138 kV lines to close gap between east and west HVDC lines Multichannel service Study and plan required to improve to Bighorn network reliability

Calgary Foothills reinforcement (FATD) OPGW to be considered for rebuild of several 240 kV lines 74S Janet – 102S Langdon Inclusion of OPGW on new 240 kV line ENMAX SS65 – 74S Janet OPGW on rebuilt 911L will tie into existing ENMAX fibre ring

Camrose Camrose – Strome Evaluation required for OPGW between east HVDC and Hanna area transmission redevelopment

B.C. Intertie Coleman – Natal OPGW to provide redundancy and meet NERC and ARS standards for BC Hydro interconnection Stock photograph.

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4.1 Overview The Long-term Transmission Plan (filed June 2012) – also referred to as the LTP or the Plan – provides an updated summary of the key inputs used in transmission analysis, describes the process and steps involved in completing the evaluations, defines the essential planning criteria to be addressed, and culminates in a summary of recommended transmission projects required to meet system need. This section describes in detail the actual key inputs, the analysis performed and the resulting recommendations of the Plan.

4.2 Load Forecast – FUTURE DEMAND AND ENERGY OUTLOOK (2009-2029) 4.2.1 Overview Over the last few years, domestic and global economic outlooks have changed substantially with many jurisdictions encountering significant growth slowdowns. However, Alberta’s economic fundamentals have generally remained positive. While the slowdown that started in 2008 was significant, economic stimulus packages in 2009 around the world improved the economic outlook and crude oil prices have made a dramatic recovery. The injection of capital into troubled banks and the financial sector improved access to capital and companies began to increase their capital budgets and drilling activity.

Toward the end of 2009 and into the first half of 2010, the outlook for major projects, including oilsands projects, began to improve. This was aided by higher crude oil prices combined with lower labour costs, low interest rates, declining cost of construction materials and the introduction of new technologies.

In the past nine years (2001-2010) Alberta Internal Load (AIL) peak demand has grown by an average of 255 megawatts (MW) or 2.9 per cent per year from 7,934 MW to 10,236 MW, an overall increase of 28.9 per cent. Electricity consumption has grown from 54,467 gigawatt hours (GWh) in 2001 to 71,723 GWh in 2010 for an overall increase of 32 per cent.

This recent trend in growth is expected to continue over the forecast period with peak demand growth forecast to be 3.3 per cent each year on average. Consumption is expected to grow 3.2 per cent each year on average during the same time period.

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4.2.2 Summary of key inputs The key factor driving the Alberta economy continues to be investment in the development of oilsands, which is largely driven by oil demand and world oil prices. This investment creates jobs and economic activity that, in general, will lead to increases in annual electricity use.

The key inputs to the load forecast are Alberta Gross Domestic Product (GDP), population growth, oilsands production and upgrading production as presented in Table 4.2.2-1.

Table 4.2.2-1: Key forecast inputs

Oilsands Upgrading A 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. Stock photograph.

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Figure 4.2.2-1: Alberta GDP and demand growth 9,000 320,000

8,500 300,000

8,000

280,000 7,500

7,000 260,000

6,500 240,000 Alberta GDP (2011 $ millions) 6,000

Average hourly Alberta Internal Load (MW) Average 220,000 5,500

5,000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 200,000

Average Alberta Internal Load (MW) Alberta GDP (2011 $ millions)

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.

Figure 4.2.2-2: Selection of 2011 and 2012 real GDP growth forecasts from various sources 6%

5%

4%

3%

Annual real GDP growth Annual real 2%

1%

0% Laurentian ERCB Alberta TD EDC BMO Conference Scotiabank CIBC RBC Conference Average Bank Finance and Economics Associates Capital Board Economics Board (used Enterprise Markets (current) in FC2009)

2011 2012

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Another key input to the FC2009 is population growth. In the FC2009, it was assumed that strong economic growth resulting from oilsands development would create jobs that incent immigration. The latest population forecasts confirm that assumption as shown by Figure 4.2.2-3. Strong population growth is still expected and has been confirmed by third party forecasts.

Figure 4.2.2-3: Alberta population forecasts 4,600

4,400

4,200

4,000

3,800

Population (000s) 3,600

3,400

3,200

3,000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Historical IHS Global Insights (January 2011 Forecast) Conference Board (used in FC2009) Alberta 2011 Budget Assumption Conference Board 2010 Forecast

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Figure 4.2.2-4: Historical comparison of load forecasts from 2007, 2008 and 2009 13,000

12,000

11,000

10,000

9,000

8,000 Average hourly Alberta Internal Load (MW) Average 7,000

6,000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Historical FC2009 FC2008 FC2007

Another comparison used to validate and test the accuracy of the AESO’s energy forecasting models is to track actual average load compared to past AESO forecasts. Figure 4.2.2-4 above compares historical average hourly AIL over the past 10 years to the forecast (FC2009) and previous forecasts (FC2007 and FC2008) going out to 2020. The 2008/2009 recession caused a delay in load growth, but as seen in Figure 4.2.2-4, 2010 shows a recovery, putting the forecast back on track.

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4.2.3 Anticipated trends As stated earlier, the key factor driving the Alberta economy continues to be growth in the oilsands sector. This growth will continue to increase load in the Northeast region, as well as in other areas of the province that supply this economic driver with materials, labour and associated infrastructure such as pipelines to move the product to market.

Alberta oilsands producers are continuing to develop oilsands leases using existing and new technologies. The trend toward higher electricity intensity compared to historical values is caused by moving into more difficult reservoir zones which require additional electrical pumps and other associated on-site loads. This is highlighted by the desire to improve steam-to-oil ratios and reduce greenhouse gas (GHG) emissions.

The industrial (without oilsands) sector has shown a drop in year-over-year energy growth from 2006 to 2009. This drop was attributed to a decline at chemicals, forestry and gas processing sites throughout the province. 2010 actuals show growth over 2009 in all these sectors and this growth trend is expected to continue with new pipelines and pipeline expansions, as well as growth from other industrial sites in the province.

Residential usage per capita is expected to continue to follow the historical trend of positive growth. Consumers’ abilities to afford larger homes, use additional appliances and electronics more than offsets historical energy efficiencies.

Figure 4.2.3-1: Forecasts of real GDP growth in Alberta 7%

6%

5%

4%

3%

2%

1% GDP growth

0%

–1%

–2%

–3%

–4% 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

FC2009 GDP Assumption Alberta 2011 Budget Assumption Conference Board Winter 2011 Update IHS Global Insights (January 2011) Conference Board 2010 Assumption

Source: The Conference Board of Canada, IHS Global Insights, Alberta Finance and Enterprise

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Figure 4.2.3-1 shows assumed GDP growth used in the FC2009 for 2009 through 2020 compared to a number of updated forecasts. As Figure 4.2.3-1 shows, FC2009 assumes very strong growth in 2011 and 2012 compared to other forecasts. The AESO assessed the validity of this strong growth when it was creating the FC2009. At the time, it was deemed reasonable as that strong short-term growth was based upon an aggressive, but rapid, economic recovery followed by more modest growth.

The AESO believes the long-term GDP growth assumption used in the FC2009 is reasonable. While strong growth is forecast for 2011 and 2012, it can also be seen in Figure 4.2.3-1 that the GDP growth assumed by the FC2009 in 2014 and 2015 is well below other, more recent third party forecasts. This means that more recent GDP forecast updates expect that growth is still going to occur but later than was expected in the FC2009.

The actual risk of delayed growth is minimal because the FC2009 attempts to capture long-run trends, not short-term fluctuations. The FC2009 assumed annual GDP growth of 3.2 per cent from 2010 to 2029. This forecast is in line with The Conference Board of Canada’s 2010 provincial long-run economic forecast of 3.3 per cent, as well as IHS Global Insight’s January 2011 forecast of 3.0 per cent over the same timeframe. Figure 4.2.4-1 shows the AESO’s forecast inputs are consistent with publicly available industry data.

4.2.4 Uncertainties and concerns looking forward The FC2009 recognizes future uncertainty in regards to timing, size and number of large oilsands extraction facilities and upgraders in the northeast of the province. This uncertainty is reflected in the FC2009 demand which shows a drop in demand from the AESO’s FC2007 in the first 10-year period. In particular, the Northeast region shows a decrease of approximately 1,000 MW by 2020 from the FC2007. However, a significant 60 per cent increase in load is still expected by 2020. In general, the results of the FC2009 show a delay of approximately one to two years in AIL peak demand by 2020/21.

The AESO continuously monitors regional forecasts against current projects in the connection queue to test the long-term forecast against current project conditions. If oilsands developers can address workforce challenges, develop expansions in modules to address project delays and incorporate new technology and improvements, the Northeast region load forecast could be understated by approximately 450 MW by 2015 and 370 MW by 2020.

The AESO serves load in the Fort Nelson area of B.C. This load is included in the AESO forecast based on information provided by BC Hydro. There is uncertainty regarding the rate of possible load development in this area, specifically related to future development of the Horn River Shale Basin, as well as potential development of a future transmission line connecting Fort Nelson to BC Hydro’s grid.

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Future load considerations the AESO has noted are changing trends in demand response, conservation and energy efficiency, as well as environmental costs. Future policy changes may have an impact on Alberta’s energy producing sectors including how they use natural gas and electricity to meet their environmental requirements. The AESO will continue to study and monitor the development of distributed generation offsetting grid load as well as how electricity is used in a variety of residential, commercial, industrial and oilsands sites. Additional information on load can be found in Appendix D.

The key FC2009 assumptions of GDP growth, oilsands production growth and population growth all remain in line, or are lower than the latest forecast updates. Therefore, the AESO believes that the key input assumptions used in the FC2009 remain valid, and the FC2009 remains appropriate for long-term transmission planning.

Figure 4.2.4-1: Comparison of inputs used for GDP growth, population growth, and oilsands production growth and latest updates 3.4% 1.7% 6.9%

3.3%

1.6% 6.8%

3.2%

3.1% 1.5% 6.7%

3.0%

Forecast annual average growth rate annual average growth Forecast rate annual average growth Forecast 1.4% rate annual average growth Forecast 6.6%

2.9%

2.8% 1.3% 6.5% GDP growth Population growth Oilsands production growth FC2009 assumption Range of updated forecasts for each input

Bars represent the range of uploaded third party forecast for each input.

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4.3 Generation Forecast To provide an outlook for the future transmission system required in Alberta, information about the size, location and type of future generation that may develop in the province is required. Generation development is a competitive business, which makes forecasting the timing and location of new generation challenging. To address this challenge, the AESO continually evaluates generation project development as well as expected changes to the drivers and costs of the development of various generation technologies. To ensure the transmission system is adequately planned to provide reliable power to Albertans and to facilitate the competitive electricity market, the AESO created a baseline forecast and a corresponding range of generation scenarios against which the transmission system is tested to identify where system reinforcement could be required to meet future need.

A number of key changes since filing of the 2009 LTP have shaped the updated assessment of future generation. The most significant factors include:

n An expectation of future climate change policy that leads to a reduced greenhouse gas cost of approximately $30/tonne in 2020.

n The federal government announcement related to coal emission standards being fixed at natural gas emission levels.

n The federal government announcement that speaks to coal-fired generation retirements occurring at the later of 45 years (facility end of life) or expiration of Power Purchase Arrangements (PPAs).

n Expectations of healthy natural gas supplies and stable long-term gas prices.

n The expiration of the federal subsidy program for renewable power generation and no current indication of a provincial subsidy being employed or its impact on future wind generation opportunities.

n The potential for increased development of cogeneration facilities in the Northeast region of Alberta.

n Recent industry announcements associated with new generation facility requests and the closure of existing generation facilities.

Development of additional generation in Alberta will be driven by growth in demand as well as the need for capacity to replace retired units. The reduction in generation capacity due to plant retirements, in combination with the consumption forecast by the AESO in the FC2009, means that approximately 6,000 MW of new effective generation is expected to be developed by 2020, with 5,000 MW to meet load growth and 1,000 MW to replace retiring capacity. Effective capacity accounts for derates to intermittent resources such as wind and is less than installed capacity. By 2029, nearly 13,000 MW of effective additions are expected to be added in Alberta, approximately 8,700 MW to meet load growth and 4,300 MW to replace retiring capacity (see Figure 4.3-1).

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Figure 4.3-1: Alberta forecast of effective generation capacity requirements 25,000

20,000

15,000 MW

10,000

5,000

0

2010/2011 2011/2012 2012/2013 2013/2014 2014/2015 2015/2016 2016/2017 2017/2018 2018/2019 2019/2020 2020/2021 2021/2022 2022/2023 2023/2024 2024/2025 2025/2026 2026/2027 2027/2028 2028/2029 2029/2030 Existing coal Existing gas Existing effective hydro Effective existing other Forecast peak demand (AIL) Expected effective generation capacity Effective existing wind

By 2020, total effective generation capacity is expected to grow from 11,901 MW to approximately 17,000 MW. While Alberta’s supply is currently weighted toward thermal coal-fired generation, this is expected to change given the aforementioned factors coupled with the following key principles:

n Natural gas-fired generation is anticipated to supply the growth gap to 2020.

n Coal retirement at 45 years or end of PPAs, per the federal government policy statement.

n Current provincial price on carbon of $15/tonne till 2014, expected to increase post 2014.

n Amount of new wind generation still uncertain; future carbon value unknown today.

n Peaking capacity will depend on the scale and timing of wind build out.

n Cogeneration growth will continue largely as a function of oilsands growth.

n Locational diversity of future gas generation still to be tested.

n Future generation mix will largely depend on market and/or policy evolution.

n The transmission infrastructure contemplated in this LTP will facilitate development of an efficient and diverse generation mix.

n By 2020, total installed generation capacity is forecast to grow to 19,000 MW.

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Figure 4.3-2: Generation mix: current and 2020 baseline

Current installed capacity 2020

44% Coal 5,782 MW 29% Coal 5,588 MW 41% Gas 5,371 MW 50% Gas 9,634 MW 7% Hydro 879 MW 5% Hydro 981 MW 6% Wind 777 MW 13% Wind 2,500 MW 2% Other 203 MW 2% Other 395 MW

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.

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4.3.2 Coal The proposed regulation on coal plant emission standards would make coal-fired generation prohibitively expensive for new additions post 2015. Beyond the Keephills 3 plant, no new conventional coal plants are expected in Alberta in the baseline generation scenario. Instead, gas-fired generation is expected to be developed as discussed previously. This is a major difference from the 2009 LTP, which considered several conventional coal resources to be viable generation options for development prior to 2020.

Prior to 2020, a modest amount of new coal capacity will be added to Alberta’s system with the connection of Keephills 3, a supercritical pulverized coal plant currently under construction and slated for commissioning in 2011. The plant has potential for carbon capture and storage in 2015. These developments, coupled with the potential for upgrades at existing plants and the possibility of a demonstration combined cycle unit fired by syngas created through underground coal gasification, support this view. Beyond 2020 it is expected that clean coal technologies will become commercially available as a result of extensive research and development funding worldwide. This will create an option for developing Alberta’s abundant coal resource.

4.3.3 Wind Wind resources remain strong in Alberta; however, there is uncertainty about the economics of wind generation and future revenue from green attributes. As of the first quarter of 2011, indications are that up to 1,600 MW of wind projects have received power plant approvals from the Alberta Utilities Commission (AUC), have applications before the AUC, or have purchased turbines. Forecasting longer-term wind development required an assessment of the economics of wind development including green attributes and future market prices. Overall, the result is a baseline forecast of wind capacity reaching a total installed capacity of 2,500 MW in Alberta by 2020. The forecast strikes a balance between the Provincial Energy Strategy’s direction to support the development of green energy (specifically wind) and recognition of the uncertainty surrounding the economics of wind generation in Alberta and the attractiveness of locating development in other jurisdictions. AESO file photograph.

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4.3.4 Other renewable projects and new technologies There are numerous biomass, small hydro and waste heat projects proposed for the province. Policies and grants (i.e., Alberta bio-energy grants) to promote these types of developments are likely to continue and be available in the future, helping the development of smaller (100 MW or less) renewable projects.

Additionally, various generation technologies such as batteries, solar, flywheels, small nuclear and geothermal are developing. For the most part, the pace at which these technologies become commercial and economic is dependent on future climate change policy and overall development of the electricity industry. Any game-changing technologies are expected to come about post 2020.

4.3.5 Large projects Large hydro and nuclear developments have previously been proposed by developers in Alberta. However, the development (regulatory, financing, design and construction) process for these projects is likely to take over a decade. These types of developments are considered in the 2020-2029 portion of the generation forecast.

4.3.6 Baseline generation scenarios Table 4.3.6-1 provides the detailed additions by type included in the baseline generation scenarios used to develop the LTP. Prior to 2020, the majority of generation additions are expected to come from gas-fired generation, combined cycle, cogeneration and simple cycle, and wind. These baseline generation scenarios were validated through market simulations to ensure the mix of generation adequately meets load and market signals that would support the development of the generation mix.

With a large portion of future capacity being gas-fired, which is more flexible than other types of generation in terms of location, two scenarios are considered. The first scenario locates the majority of the gas-fired combined cycle and simple cycle additions in northern Alberta only (includes all other Alberta generation assumptions) and the second scenario locates them primarily in southern Alberta. The northern baseline scenario sees 73 per cent of the combined cycle capacity and 55 per cent of the simple cycle additions located in the north. The southern baseline scenario sees all the combined cycle and 55 per cent of the simple cycle additions located in the south.

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Post 2020, it is expected that the economics of generation will evolve due to the impact of climate change policy and the costs of GHG and technology development. Overall this may shift the emphasis from gas-fired additions to clean coal technology and long lead-time projects like hydro and nuclear, which are included in the baseline generation scenario near the end of the 2020 decade. Climate change policy and related funding and research could lead to the development and commercialization of new technologies. The technologies that prove to be the front runners in North America and Alberta are still to be determined; however, 700 MW capacity was included in the baseline scenarios post-2020 to account for these new technologies. Currently these new technologies are expected to be geothermal, small nuclear, biomass, commercial combined heat and power, solar and other distributed types of generation.

The post 2020 baseline shows two options in Figure 4.3.6-1. Both have a similar increase in generation capacity but outline different potential for location and fuel type, which is useful in analyzing the impact on the system. The first baseline (coal renaissance) considers the addition of substantial clean coal capacity of 970 MW. The second baseline (nuclear develops) considers the alternative case of 1,000 MW of nuclear generation in the province. Both baselines include a potential for 1,500 MW of hydro development.

Figure 4.3.6-1: 2029 Baseline scenario generation mix

2029: Coal renaissance 2029: Nuclear develops

55% Gas 13,832 MW 53% Gas 13,539 MW 18% Wind 4,500 MW 18% Wind 4,500 MW 14% Coal 3,424 MW 11% Coal 2,724 MW 10% Hydro 2,481 MW 10% Hydro 2,481 MW 4% Other 1,095 MW 4% Other 1,095 MW 4% Nuclear 1,000 MW

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.

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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.

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 16,678 20,565 20,565 demand and reserve margin 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

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4.4 Bulk Transmission System including CTI 4.4.1 Overview The AESO plans Alberta’s transmission system by evaluating requirements within various geographic regions in the province and the bulk system that interconnects these regions.

The bulk transmission system is the integrated system of transmission lines and substations that delivers electric power from major generating facilities to load centres. The bulk system also delivers power to, and receives power from, neighbouring jurisdictions. The bulk transmission system generally includes the 500 kilovolt (kV) and 240 kV transmission lines and substations.

The bulk transmission system is essential to overall system reliability, forming the backbone that delivers bulk power to load centres, connects new and existing generation and enables import and export transactions with neighbouring jurisdictions.

The AESO’s technical analysis examines and identifies the required reinforcements of the bulk transmission system, aligning which facilities are required in a specific timeframe to meet forecast generation and load requirements and planning scenarios, and to facilitate the attainment of the objectives in the Provincial Energy Strategy.

The bulk system is studied by defining transmission cutplanes. These cutplanes combine the loading on groups of transmission lines that connect two regions within the bulk system. The four major cutplanes used to study the bulk transmission system in Alberta are:

1. Edmonton to northeast transmission path (NE cutplane) – There are currently two 240 kV lines between Edmonton and the northeast area. These two lines, plus a number of 138 kV lines, interconnect the Edmonton area with the northeast area and are referred to as the Northeast (NE) cutplane.

2. Edmonton to northwest transmission path (NW cutplane) – There are currently three 240 kV lines between the Wabamun Lake area and the northwest area. These three lines, plus a number of 138 kV lines, interconnect the Wabamun Lake area with the northwest area and are referred to as the Northwest (NW) cutplane.

3. Edmonton to Calgary transmission path (SOK cutplane) – There are currently six 240 kV transmission lines between Edmonton and the Red Deer area. These six lines, plus a number of 138 kV lines, carry all the power from northern Alberta, south from the generating plants in the Wabamun Lake area (Keephills, Genesee, and Sundance) to central and southern Alberta and are referred to collectively as the South of Keephills-Ellerslie-Genesee (SOK) cutplane.

4. South to Calgary transmission path (South cutplane) – There are currently three 240 kV lines between the south area and the Calgary area. These lines, plus a number of 138 kV lines, interconnect the south area with the Calgary areas and are referred to as the South cutplane. In addition, the South cutplane includes the 500 kV line from B.C. to Calgary.

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Figure 4.4.1-1: Existing bulk transmission system and cutplanes

1. Northeast

2. Northwest

3. SOK

4. South

SUBSTATIONS Existing transmission lines 240 kV 500 kV Bulk cutplanes

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Besides the four cutplanes internal to Alberta, there are two interties to other jurisdictions that are considered part of the bulk system:

Alberta to B.C. transmission path – There are currently one 500 kV and two 138 kV lines between Alberta and B.C. These three transmission lines collectively constitute the intertie to B.C. Through this intertie, Alberta is connected to the B.C. system and on through to the transmission systems in the U.S. Pacific Northwest and the rest of the systems comprising the Western Interconnection of North America.

Alberta to Saskatchewan transmission path – Synchronous operation with Saskatchewan is not possible as it is part of the Eastern Interconnection of North America and Alberta is part of the Western Interconnection. These two large interconnected systems are joined together via high voltage direct current (HVDC) back-to-back (i.e., asynchronous) links at various points in Canada and the U.S. (refer to Figure 1 in Appendix G for a map showing the Eastern and Western Interconnections). The Alberta-Saskatchewan intertie comprises an asynchronous link, known as the McNeill converter station, located near Empress, Alberta. The converter station is connected via a 138 kV transmission line to the Alberta system and a 230 kV line to Swift Current, Saskatchewan. This intertie provides Alberta access to the electricity markets in the Eastern Interconnection through Saskatchewan and Manitoba and the U.S. Midwest and similarly provides entities in these jurisdictions with access to the Alberta market.

The main facilities of the existing bulk transmission system and the associated cutplanes are shown in Figure 4.4.1-1. As the figure shows, the bulk system connects the major load/generation centres of Fort McMurray, Edmonton and Calgary, as well as other regions of Alberta.

4.4.2 Transmission technology alternatives There are a number of possible technological choices that could be considered to meet the long-term development requirements for Alberta’s transmission system. The system can be reinforced using transmission lines designed for alternating current (AC) operation with voltages ranging from 240 to 765 kV. A HVDC option with transmission lines designed for operation at voltages ranging from ±250 kV to ±500 kV is also possible.

Alberta currently uses 240 kV and 500 kV AC for its bulk transmission system and it is anticipated that facilities at these voltage levels, along with the planned 500 kV HVDC lines, will provide the appropriate balance between capacity and cost in the Alberta context. A significant portion of the bulk transmission systems in the western half of North America uses the same voltage levels and for these reasons, these voltage levels are considered appropriate for future transmission development in Alberta. However, HVDC transmission is recognized as providing the required power transfer capacity with a lower overall land-use impact, it provides the ability to directly control both power flow quantity and direction, and is consistent with government policy. For these reasons, HVDC has been selected as the preferred technology choice for those situations where these attributes are seen as significant advantages for the long-term development of the bulk transmission system in Alberta.

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4.4.3 Project status 4.4.3.1 Edmonton to Calgary transmission system reinforcement The existing transmission system that delivers power from the Edmonton region to the South region relies on six 240 kV transmission lines in the Edmonton to Red Deer area and seven 240 kV lines between Red Deer and Calgary. Lower voltage lines (138 kV and 69 kV) also contribute to the aggregate capacity but the majority of the capacity is provided by 240 kV lines. The system connecting these two regions has not been upgraded since the early 1990s. Load growth in southern and central Alberta is stressing the existing system such that capacity will fall short of reliability requirements by 2014. Currently, when one of the existing six lines is removed from the grid for maintenance or due to forced outages, system congestion occurs.

Reinforcement of the transmission system between the Edmonton and Calgary regions is needed to avoid reliability issues for consumers in south and central Alberta, improve the efficiency of the transmission system, restore the capacity of existing interties, and avoid congestion that prevents the market from achieving a fully competitive outcome. Transmission constraints and congestion also slow development of new competitive generation in the Edmonton area and further north.

Meeting the long-term capacity requirement for the Edmonton to Calgary component of the bulk system using high-capacity HVDC transmission lines makes most efficient use of rights-of-way and minimizes land-use impacts.

While a number of factors and conditions are considered in making this technology choice, including consultation, economics and efficiency, a priority is given to minimizing land-use impacts in support of government policy presented in the Provincial Energy Strategy, which suggests the use of HVDC technology where possible.

Two HVDC high-capacity lines are planned to be in service by 2014. Analysis indicates the preferred orientation of these lines is for one line on the west/central portion of the province connecting the existing Wabamun Lake/Edmonton hub to the Calgary area hub. The preferred orientation of the second line is on the eastern side of the province, connecting the Heartland hub northeast of Edmonton to a southern hub near West Brooks. Each line will initially be designed for 1,000 MW capacity with provision for expansion to 2,000 MW in future. The AESO has determined the future expansion will likely be needed beyond 2020.

Construction of both lines substantially increases the usable capacity of the first line. The first line alone cannot be fully utilized without the second line being in service as the loss of the first line would create too large a contingency on the system. Construction of these lines removes uncertainty and sends a clear and positive signal to consumers, generation and intertie developers that unrestricted access to transmission capacity will be in place to deliver future generation to the market and reliably meet the electricity needs of consumers in central and southern Alberta.

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The two new HVDC lines will strengthen the transmission system between Edmonton and Calgary such that it will be sufficient to meet the needs of this corridor for over 10 years, before future capacity upgrades are required as outlined previously. The right-of-way requirements for the two lines are substantially less than all other AC technology alternatives. More gradual additions of single circuit AC lines would result in up to 10 additional transmission lines to achieve the same capacity, more than doubling the right-of-way requirement of the HVDC lines.

The estimated cost of each of the HVDC lines considered in the LTP, including converter stations, is approximately 50 to 90 per cent higher than a double circuit 500 kV AC line.

The two high-capacity lines will remove uncertainty for generation and intertie developers. Alberta’s transmission system will be capable of providing efficient and unrestricted access for many years, thereby facilitating investment decisions by generation developers.

The lines also facilitate access between renewable generation zones and the market to transport large quantities of electricity when the wind is blowing or when high river flows occur at hydro plants.

Adding a higher capacity transmission line reduces how often the system must operate near its limit, thereby reducing line losses. Improving system efficiency saves money and is environmentally beneficial as it reduces greenhouse gases and other emissions created during the production of wasted energy.

Currently, interim technical measures have been required to allow connection of new generation. These measures are used as a last resort until the transmission system can be reinforced. All forms of generation in the north will be constrained to some degree until the needed transmission facilities are in place. Transmission reinforcement takes longer to implement than generation projects, and must be developed well in advance of specific generation projects.

Based on analysis of the generation scenarios described earlier, the AESO has determined that proceeding with the development of both lines with in-service dates of 2014 is prudent. In addition, development of both lines at this time takes advantage of the current market conditions for procuring materials and synergies that can be achieved in engineering, procurement and construction.

Implementing high-capacity alternatives exposes the system to situations where a large loss of capacity can occur; however, adding both circuits at the same time permits each line to back up the other and minimizes exposure to service interruptions. The transmission facility owners (TFOs) of the two HVDC lines have filed their facility applications with the AUC to support the in-service dates.

The AESO will continue to monitor generation development in the province. Should there be a major difference between the assumed generation scenarios and actual development, the AESO will review all assumptions, adjust its plans accordingly, and reassess its project development strategy.

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Figure 4.4.3.1-1: Edmonton-Calgary transmission system reinforcement

40 Wabamun 33 Fort Sask. 60 Edmonton

56 Vegreville 13 Lloydminster

29 Hinton / Edson

31 Wetaskiwin

30 Drayton Valley 32 Wainwright

37 Provost 36 Alliance / Battle River

35 Red Deer 34 Abraham Lake 38 Caroline

42 Hanna 39 Didsbury

57 Airdrie

44 Seebee 43 Sheerness 45 Strathmore / Blackie

6 Calgary

48 Empress

47 Brooks

46 High River

49 Stavely

Edmonton-Calgary transmission system reinforcement n 2014 ISD The lines also facilitate access between n Two 500 kV HVDC lines (1,000 MW each) renewable energy zones and the market – West-Genesee to Langdon to transport large quantities of electricity – East-Heartland to Brooks when the wind is blowing or when high n Expandable to 2,000 MW each river flows occur at hydro plants. n Required to: – Address reliability issues – Improve efficiency – Accommodate long-term growth – Support energy market n Included in 2009 LTP as CTI

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4.4.3.2 Heartland transmission system reinforcement The oilsands industry is expected to continue to grow and is the primary driver of the need for new electricity infrastructure development in the northeastern part of Alberta, followed by growth in pipelines and associated pumping loads. There are two main components of load associated with extracting and processing bitumen. The first component includes facilities used to extract bitumen from the oilsands. This can be in the form of a mining-type operation that extracts the oilsands from its original location and moves it to a processing facility where bitumen is separated from sand. It can also be in the form of in situ recovery of bitumen directly out of the oilsands formation. In Alberta, most of this activity is located in the Fort McMurray, Cold Lake and Peace River areas.

The second component of oilsands load is the demand for power associated with upgrading bitumen into synthetic crude oil in a refinery-type facility. These facilities can either be located close to bitumen extraction sites (e.g., Fort McMurray area) or in another area with bitumen piped to the facility (e.g., Fort Saskatchewan/Heartland area).

The existing transmission system into the Northeast region and Heartland area is constrained. The northeast is currently supplied by a double circuit 240 kV line from Edmonton through Fort Saskatchewan, and a single circuit 240 kV line from Wabamun to the Fort McMurray area. Reinforcement of the transmission system between Edmonton and the Heartland is required to avoid system reliability issues in both the Heartland area and the Fort McMurray area.

Currently, interim technical measures in the form of operating procedures are required to ensure reliable supply to the northeast. Continued constraints and congestion will slow oilsands and bitumen upgrading development in Alberta. Adding high capacity 500 kV lines into the area will facilitate investment decisions by oilsands developers. These decisions not only relate to potential load growth in the area, but can also facilitate increased cogeneration opportunities by allowing excess electric generation at these sites to connect to the transmission system, providing new generation sources for the Alberta grid.

The proposed 500 kV double circuit line from the existing Ellerslie substation in south Edmonton to a new substation in the industrial Heartland area will strengthen the transmission into the area and will provide a strong source for an eventual 500 kV line into the Northeast region. This transmission enhancement not only reinforces the system between Edmonton and the northeast but also provides a termination point for the proposed east HVDC line.

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Figure 4.4.3.2-1: Heartland transmission system reinforcement

27 Athabasca / Lac La Biche

33 Fort Saskatchewan

40 Wabamun

60 Edmonton

30 Drayton Valley 31 Wetaskiwin

Heartland 500 kV n 2013 ISD n Double circuit 500 kV from Ellerslie n Required to: – Supply northeast load – Interconnect east HVDC – Supply Heartland load n Identified in 2009 LTP as CTI

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Figure 4.4.3.3-1: Fort McMurray transmission system reinforcements

East 500 kV Fort McMurray

Fort McMurray

19 Peace River West 500 kV Fort McMurray

21 High Prairie

23 Valleyview

26 Swan Hills At habasca / Lac La Biche

28 Cold Lake

24 Fox Creek

40 Wabamun

56 Vegreville 60 Edmonton 13 Lloydminster

29 Hinton / Edson

East 500 kV Fort McMurray n 2021-2022 ISD n Connects 500 kV from Heartland n Required for northeast load n Identified in 2009 LTP as CTI

West 500 kV Fort McMurray n 2017 ISD n Two stages 1. Thickwood-Livock operated at 240 kV 2. Genesee-Livock 500 kV and conversion of Thickwood-Livock to 500 kV n Required for northeast load n Identified in 2009 LTP as CTI

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4.4.3.3 Fort McMurray transmission system reinforcements As with the transmission reinforcements required into the Heartland area, transmission reinforcement into the Fort McMurray area is driven by oilsands development.

The Fort McMurray area is unique from a planning perspective as it has a significant number of large industrial customers. These customers will be contracting both demand transmission service (DTS) and supply transmission service (STS) with varying degrees of usage to supply process requirements and for electric supply reliability. Planning for a transmission system that is capable of handling the full range of all contracted DTS and STS will result in large capital investments. On the other hand, not planning for the full range of DTS and STS can result in congestion and possible violation of the AESO’s reliability criteria. The solution is to find the most likely maximum load and supply scenarios that the Fort McMurray region will experience during the next 10 years and plan accordingly, taking into account any necessary revisions.

The specific facilities recommended for this reinforcement are a 500 kV AC line from the Genesee generating station to a new 500 kV substation in the Fort McMurray area (Stage 1) and a 500 kV AC line from the new Heartland substation to the new Fort McMurray 500 kV substation (Stage 2). The AESO validates the configuration of these lines as described in the Electric Utilities Act as follows:

Stage 1A: A transmission line from a new substation to be built in the Thickwood Hills, approximately 25 kilometres (km) west of the Fort McMurray Urban Service Area, to a substation at or in the vicinity of the existing Brintnell 876S substation. This segment will be initially energized to 240 kV and be interconnected with a substation near Brintnell. Upon completion of Stage 1B, the entire line (Stage 1A and 1B) will be energized to 500 kV.

Stage 1B: A transmission line at or in the vicinity of the existing Brintnell 876S substation to a substation in the vicinity of the existing Keephills-Genesee generating units.

Stage 2: A transmission line located east of the facilities described in Stage 1 and geographically separated from those facilities for the purposes of ensuring reliability of the transmission system, from a new substation to be built in the Gibbons-Redwater region, to a new substation to be built in the Thickwood Hills area, approximately 25 km west of the Fort McMurray Urban Service Area.

Based on analysis of the load and generation scenarios, the AESO has determined that Stage 1 of the Fort McMurray line should be in operation in 2017. The in-service date of Stage 2 is determined to be sometime after 2020.

The AESO has been continually monitoring load growth and generation development in the area based on review of connection requests received, information received from transmission and distribution facility owners, various industry announcements and from direct consultation with oilsands developers. The AESO reviews and assesses this information and determines if any adjustments are required to project in-service dates should business conditions associated with loads and generation change.

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4.4.3.4 Southern Alberta Transmission Reinforcement (SATR) The South region is currently Alberta’s primary wind power generation area. As of April 30, 2011, the AESO has received requests for connection of nearly 6,700 MW of wind power, of which over 5,000 MW is located in the South region. The AESO connections queue and project list are updated monthly to reflect the progress of projects. For the most recent queue, visit the AESO website at www.aeso.ca and follow the pathway Customer Connections > Connection Queue. These numbers are considerably lower than the forecast used in the 2009 LTP. It is expected that not all wind generation that has requested connection to the system will be constructed, and there is uncertainty about where the projects will ultimately be located.

Regardless of the location of future wind turbines, there is currently insufficient capability in the South region transmission system to meet the needs of the existing and proposed generation. Given existing system constraints, the South region transmission system will require substantial improvements, including multiple new 240 kV transmission system loops and substations and upgrading of existing facilities to accommodate the generation connections.

The AESO received approval from the AUC for the SATR Needs Identification Document (NID) in 2009. This project is flexible enough to accommodate various amounts of future wind development to a cumulative capacity of 2,700 MW. The project includes three stages of development, the first two stages consisting of various 240 kV lines, and a 240 kV system loop connection to the 500 kV Langdon-Cranbrook line. The third stage is a 240 kV line between Ware Junction and Langdon. Photo courtesy of Suncor Energy.

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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. Stock photograph.

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Figure 4.4.3.4-1: Bulk – Southern Alberta transmission reinforcement

43 Sheerness

6 Calgary

45 Strathmore / Blackie

47 Brooks

46 High River

49 Stavely

4 Medicine Hat 52 Vauxhall

53 Fort MacLeod

54 Lethbridge

55 Glenwood

Southern Alberta transmission reinforcement n 2011-2017 ISD n Extensive 240 kV looped system and tie to 500 kV line n Required to integrate renewable and gas-fired generation n NID approved

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4.4.3.5 Foothills Area Transmission Development (FATD) In addition to the 240 kV looped system in the south, the FATD project is an integral part of the system required to move wind energy to the load centres of the Foothills and greater Calgary area. This project includes a 240/138 kV substation near High River and two double circuit 240 kV lines from Foothills into Calgary, one to the east side of the city and the other to the west side. The project is planned to be developed in stages between 2014 and 2017.

In addition to integrating wind energy, the Foothills area development provides other benefits by creating a system that will accommodate potential gas-fired generation in and near the City of Calgary, as well as mitigating local transmission constraints within the city to facilitate future load growth.

Generation development, both wind in the south and gas-fired generation in and around Calgary, can impact the FATD project. Depending on where and how quickly these forms of generation develop, the west leg from Foothills substation to Sarcee substation may need to be advanced. The Foothills area NIDs are being developed and are expected to be filed with the AUC later this year. Photo courtesy of Capital Power Corporation.

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Figure 4.4.3.5-1: Bulk – Foothills Area Transmission Development (FATD)

Cochrane

6 Calgary

45 Strathmore

Okotoks

46 High River

Foothills Area Transmission Development (FATD) n 2014-2017 ISD n 240/138 kV substation south of Calgary n 240 kV lines east and west into Calgary n Other 240 kV enhancements n Required for reliability, load and to integrate renewable and gas-fired generation n NID under development

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4.4.3.6 South Calgary transmission system reinforcements The City of Calgary peak load is expected to reach approximately 2,000 MW by 2020. Based on information from the City of Calgary’s land use planning department, the south part of the city in particular is expected to continue to grow. The construction of a new South Health Campus in the southeast sector indicates an increasing population in the south area specifically. In addition, the South Health Campus requires a geographically separate redundant electric supply to ensure a reliable supply of electricity.

The transmission system into the south part of the City of Calgary requires reinforcement. Currently, there are three 138 kV circuits supplying south Calgary and if one of these circuits is out of service for maintenance, a subsequent outage would result in the requirement for planned outages to keep the remaining 138 kV circuit from overloading.

The proposed development to supply south Calgary includes a new 240/138 kV substation near the intersection of 88 Street SE and Highway 22X and associated 138 kV and 240 kV lines to interconnect into the existing system. The anticipated in-service date for this development is 2012. Stock photograph.

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Figure 4.4.3.6-1: CTI South Calgary source

Airdrie

6 Calgary Cochrane

Calgary local area enhancements n 2012 ISD n 240/138 kV substation in south Calgary and 138 kV enhancements n Required for load and reliability n Included in the 2009 LTP as CTI

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4.4.3.7 Northwest transmission system reinforcements The Northwest region imports power from the rest of the AIES because peak load in the region is greater than generating capacity. The region imports about 55 to 60 per cent of its annual energy supply and this means the region is dependent on its interconnections to supply its load. The transmission system in the region is currently weak and relies on generation units located in the region to provide voltage support and reliability, particularly in the far northwest corner of the area. The need to operate this generation indicates that the transmission system is not adequate to reliably serve the current load.

The Northwest region is primarily a load area and relies heavily on power transfers from the Wabamun Lake area and, under certain conditions, from the northeast. As a result, a major transmission outage between Wabamun Lake and the Northwest region could cause a phenomenon called voltage collapse, which could cause a sustained outage.

To mitigate the potential voltage collapse, the AESO is proposing two new projects. The first is a double circuit 240 kV line from Bickerdike (near Edson) to Little Smoky. The second is a re-termination of the east end of the Brintnell to Wesley Creek 240 kV line from Brintnell to Livock to tie to the west Fort McMurray 500 kV line at or near Livock. Stock photograph.

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Figure 4.4.3.7-1: Bulk – Northwest projects

Re-terminate 9L15 at new 500 kV substation

21 High Prairie 20 Grande Prairie 23 Valleyview

26 Swan Hills 27 Athabasca / Lac La Biche

24 Fox Creek

240 kV bulk reinforcement into NW

40 Wabamun 33 Fort Sa sk.

60 Edmonton 29 Hinton / Edson

Re-terminate 9L15 at 240 kV bulk reinforcement into NW new 500 kV substation n 2015 ISD n 2017 ISD n 240 kV double circuit line from Bickerdike n Re-terminate Brintnell end of n Required to mitigate voltage collapse Brintnell-Wesley Creek 240 kV line and overloads n Required to mitigate voltage n New project collapse and overloads in northwest n New project

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4.4.4 Bulk projects cost estimates and timelines The bulk projects are at various stages of completion with some having filed NIDs and some NIDs approved by the AUC, while others are still at the conceptual stage. The CTI projects are included in the bulk system infrastructure.

These projects are listed in Table 4.4.4-1 along with a brief description and the estimated ISD. The transmission capability increases provided by these developments are assumed to have been achieved when assessing the future needs on the bulk transmission system.

Table 4.4.4-1: Bulk transmission system projects

C 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

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.

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4.4.5 Unique considerations and uncertainties on the bulk system In order to capture uncertainty that could impact the bulk system transmission requirements in the future, additional scenarios and sensitivities to the baseline assumptions are considered. These allow for the evaluation of typically larger scale generation trends that may occur and directly impact future need requirements. To that end, the AESO also developed three alternate generation scenarios referred to as:

n GS1 – Greenest

n GS4 – High cogeneration

n GS5 – Continuation of coal generation

These scenarios change the type, location and amount of generation in various areas of the province and will have different impacts on power flows through the system. The AESO examined the impacts of these scenarios on the timing of the recommended transmission upgrades:

GS1 – Greenest scenario GS1 is the greenest scenario and is distinguished by 1,500 MW of additional wind energy in the South and Central regions (1,020 MW and 480 MW respectively).

The recommended system enhancements were included in the study cases with the exception of Stage 3 of the South Area Transmission Reinforcement, which is a double circuit 240 kV line from Ware Junction to Langdon. Stage 3 is not required for the baseline generation assumption of 2,500 MW of wind by 2020.

Results show additional reinforcement will be required under GS1. The most significant issue is apparent voltage instability for several 240 kV outages in the South as well as outages in the Central region. Overloads also occur under certain conditions; however, these tend to be localized issues. The AESO will continually monitor wind development in Alberta and recommend additional local reinforcement if and when it appears more wind than forecast will develop.

GS4 – High cogeneration scenario GS4 is the high cogeneration scenario that sees the addition of about 850 MW of cogeneration in the Fort McMurray area.

The recommended enhancements modelled in the study case included the west Fort McMurray 500 kV line but not the east Fort McMurray 500 kV line as it has currently been assessed with an in-service date of 2021-2022.

Results indicate the bulk system as planned can easily accommodate the change in flows resulting from the addition of cogeneration in the Fort McMurray area. Local regional overloads may occur due to some specific generation locations. The AESO will continually monitor the generation development and may recommend local reinforcement as needed.

GS5 – Continuation of coal generation scenario GS5 assumes current coal technology will continue. The main difference between GS5 and the baseline scenarios is the replacement of the Swan Hills coal gasification plant with combined cycle generation. Combined cycle plants like Swan Hills are in the northern part of the province and the impact on flows on the transmission system is small.

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Study results indicate there are overloads on two 240 kV circuits in the Wabamun Lake – Edmonton area for common tower failures between Wabamun Lake area and Edmonton, and within Edmonton. This would suggest that for GS5, further strengthening of the system between Wabamun and Edmonton will be required. This assumes the Swan Hills generation facility is replaced in part by a combined cycle generator in the Wabamun area. If the generation is located elsewhere in the province, it will change requirements for transmission reinforcement.

In addition to the above generation scenarios, the following considerations have been taken into account:

n As mentioned earlier, the Fort McMurray area is unique from a planning perspective as it has a significant number of large industrial customers. These customers will be contracting both demand transmission service (DTS) and supply transmission service (STS) with varying degrees of usage to supply process requirements and for electric supply reliability. Planning for a transmission system that is capable of handling the full range of all contracted DTS and STS will result in large capital investments. On the other hand, not planning for the full range of DTS and STS can result in congestion and possible violation of the AESO’s reliability criteria. The solution is to find the most likely maximum load and supply scenarios that the Fort McMurray region will experience during the next 10 years.

n Each of the regions studied in the LTP have unique load and generation characteristics. Changing certain primary assumptions could have an impact on the timing of transmission reinforcements between the areas.

n The three regions where these assumptions could have the greatest impact are: – Northwest – the baseline generation scenario considered the addition of a 375 MW coal gasification combined cycle plant near Swan Hills and a development at H.R. Milner by 2020. If these generation facilities do not proceed, the resulting requirements for transmission into the northwest will be significantly impacted. – Northeast – in addition to the possibility of higher than anticipated cogeneration, which is identified as Generation Scenario GS4 and examined as part of the generation scenario sensitivity analysis, the possibility also exists for loads to increase or cogeneration to be lower than proposed in the base scenario. Either of these conditions could result in changes to in-service dates and the possibility of requiring new projects for transmission reinforcement into the northeast. – South – generation additions in the south include simple cycle and combined cycle gas-fired facilities that total about 1,700 MW. If one or more of the major facilities proposed for the south do not materialize, flows on the north-south cutplane will be higher than anticipated. In addition to reduced generation in the south, it is also possible that wind energy will increase more quickly than anticipated. This uncertainty was examined in GS1, the greenest generation scenario identified above. The HVDC system being planned has the required design margin to accommodate such scenarios.

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Sensitivities if generation projects do not proceed as anticipated

Swan Hills The Swan Hills coal gasification project is anticipated to be in service in the 2018-2019 timeframe. Given that this is new technology, there is some uncertainty regarding the timing of this facility.

Studies were run to test the system in 2020 without this facility. Results indicate the system is sufficiently robust that if the Swan Hills facility is not in place in 2020, no further enhancements will be required in that timeframe. This assumes the west 500 kV line to Fort McMurray is in place and the 9L15 line is re-terminated at Livock.

Saddlebrook In the north baseline generation scenario, Saddlebrook is anticipated to be online in 2015. If the north scenario materializes and Saddlebrook does not proceed, north-south flows will increase.

Results of the studies indicate the system is sufficiently robust should Saddlebrook not proceed under the north generation scenario. The only problem seen in this scenario is a localized 240 kV overload in Edmonton for a common tower failure. This assumes that both HVDC 500 kV CTI lines are in place.

Northeast cogeneration The baseline generation scenarios include 17 new cogeneration facilities that would add 1,470 MW of generation in the Fort McMurray area. If approximately 25 per cent of these projects do not materialize, it could impact flows into the northeast from the Edmonton region.

The system was tested removing five of the proposed projects for a total reduction in northeast generation of 340 MW. Results indicate the system as proposed is robust enough to allow for increased flows into the northeast should 340 MW of cogeneration not materialize.

Northeast loads For this analysis, loads in the northeast were gradually increased from the expected 2020 levels to determine the point at which the system could no longer be operated reliably.

Loads in the northeast were gradually increased to determine at what point the transfer capability would be exceeded under contingency conditions (single outages and common tower failures). The maximum increase was set at 830 MW or about 20 per cent of the forecast 2020 load. The first constraint occurs at an increase of 170 MW and is an overload on a 138 kV line in the Fort Saskatchewan area for a double circuit common tower outage. Other constraints are seen at about 250 MW, 560 MW and 750 MW all on 138 kV circuits with the last one being in the Athabasca area.

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The sensitivity analyses described previously show that the bulk system being planned is robust enough to accommodate various uncertainties associated with load growth and generation development. However, local regional reinforcement may be required based on geographic location of the load and generators. The AESO will continue to monitor the load growth and generation development and initiate system changes as required.

Should there be a major difference between the assumed generation scenarios and actual development, the AESO will review all assumptions, adjust its plan accordingly and reassess its project development strategy.

4.4.6 Bulk transmission system post-2020 Determining the need for projects in the post-2020 period reflects and builds on the analysis of the first 10-year horizon. The projects identified with in-service dates pre-2020 serve as a starting point for the post-2020 period planning evaluation. A more generic approach is undertaken with a focus on power flows across major bulk system cutplanes. The system is stress tested to determine its continued ability to meet expected load growth on the Alberta Interconnected Electric System beyond 2020.

As indicated in the previous section, a number of projects originally identified in the 2009 LTP have had their in-service dates adjusted to the post-2020 period after a refreshed analysis for this LTP:

Table 4.4.6-1: Bulk system projects with ISDs post 2020

Project In-service date

North Calgary 240 kV supply 2021 CTI: East Fort McMurray 500 kV 2021-2022 CTI: increase capacity of both 500 kV HVDC lines Post 2020

The post-2020 assessment was performed by incrementally increasing the flows between regions and examining the limits of those flows under single contingencies and double contingencies where two circuits are on the same towers. Typically, the analysis of these two cases identifies the need for transmission enhancements. Stock photograph.

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The assessment identifies the flow levels at which overloads or voltage stability issues begin to occur. Outage simulations were conducted only on 240 kV and above facilities but facilities at 138 kV and below were also monitored.

The following speaks to the specific conditions and impacts seen in this analysis:

Northwest region The assessment was performed by increasing loads in the Northwest region and correspondingly increasing generation in the Edmonton and South regions.

Results indicate that the overloads on 138 kV circuits into and within the Northwest region are first seen when flow increases exceed about 80 MW. The number of overloaded 138 kV elements increases rapidly once flows are increased beyond about 140 MW. The load in the Northwest region is expected to increase at about 40 MW per year, which means system enhancements may be required within the 2022-2023 timeframe. This will depend on generation additions in the Northwest region that might offset load increases.

Northeast region The assessment was performed by increasing the loads in the Northeast region and correspondingly increasing generation in the Edmonton and South regions. This is the same assessment that was performed for the sensitivity study discussed in Section 4.4.5, Northeast Loads.

The first overload on the local area 138 kV system shows in Fort Saskatchewan when flows into the Northeast region are increased by 180 MW. Subsequent overloads are also within the Fort Saskatchewan area. These are local area issues for double contingency outages and can likely be mitigated through operating procedures. Local cogeneration development will either eliminate or reduce the overloads. Photo courtesy of TransAlta Corporation. Photo courtesy of TransAlta

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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. AESO file photograph.

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Figure 4.5.1.1-1: Existing Northwest transmission system

Northwest ZAMA Load (MW) 2010 winter peak 1,039 2020 forecast winter peak 1,450

Generation (MW) SULPHUR POINT High Level Current installed 798 RAINBOW LAKE 2020 forecast installed 1,330 – 1,800 MELITO

BASSETT BLUMENORT

HAIG RIVER

CHINCHAGA RIVER KEG RIVER

KEMP RIVER

HAMBURG

MEIKLE

HOTCHKISS Manning CADOTTE RIVER KIDNEY LAKE

NORCEN DAISHOWA CARMON

HINES CREEK Peace Fairview River LUBICON

BOUCHER CREEK NIPISI Spirit River

KSITUAN RIVER RYCROFT Falher McLennan SADDLE HILLS NARROWS CREEK

Sexsmith High Prairie Beaverlodge Wembley KINUSO Grande Prairie Slave Lake Valleyview ELMWORTH WAPITI LITTLE SMOKY

Swan Hills

LOUISE CREEK VIRGINIA HILLS DOME CUTBANK SIMONETTE FOX CREEK

KAKWA RIDGE BENBOW H.R. MILNER KAYBOB WHITECOURT

SUBSTATIONS Grande Cache Existing transmission lines 69 kV/72 kV 240 kV 138 kV/144 kV

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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. Photo courtesy of TransAlta Corporation. Photo courtesy of TransAlta

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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 C 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 Photo courtesy of ATCO Electric. Photo courtesy of ATCO

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4.5.1.3 Unique challenges, uncertainties and concerns The current plan for the northwest is heavily dependent on the assumption that two large generators will be developed in the area. If either or both of these projects do not proceed as anticipated, the local area transmission plan will need to reflect this change, and significant transmission reinforcement will still be required to support anticipated new loads in the region.

The potential also exists for renewable generation such as hydro and wind to be added to the system in the northwest post 2020. Should this source of generation develop, it will impact the need for local as well as inter-regional transmission reinforcement.

There is also potential for oilsands development in the Peace River area that could impact the requirement for local area transmission reinforcement. The re-termination of the east end of the Brintnell-Wesley Creek 240 kV line from Brintnell to Livock will help support load growth in the Peace River area.

Unconventional oil and gas resource development in the Drayton Valley and Hinton-Edson areas is a potential driver for additional load growth. The load forecast in the LTP accounts for some growth in the area. The AESO will continue to monitor the development to assess if further transmission development is required.

In addition to the uncertainty within Alberta, BC Hydro has forecast significant load growth in the Fort Nelson, B.C. region that exceeds the load forecast used in the development of the Northwest Alberta Transmission NID. The Fort Nelson area is connected to the Alberta system via a 144 kV line supplied from the Rainbow Lake substation. Additional TMR services may be required to support this incremental load until new transmission facilities can be constructed. Additional transmission facilities beyond those identified in the NID may be required for the Rainbow Lake area. Possible transmission reinforcements required to serve additional B.C. loads are not included in the LTP.

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4.5.2 Northeast region

4.5.2.1 Overview The Northeast region of Alberta is bordered on the north by the Northwest Territories, on the east by the Saskatchewan border, on the west by the Fifth Meridian and on the south by Township 60. This region includes Fort McMurray, Athabasca/Lac La Biche, Cold Lake and Fort Saskatchewan. The major transmission facilities of the Northeast region are shown in Figure 4.5.2.1-1.

Expected growth The majority of the electrical load and generation in the region is located at oilsands sites surrounding the City of Fort McMurray and in the Cold Lake area. This region is unique as it has significant behind-the-fence load and generation connected to the grid as industrial systems.

The Northeast region is expected to experience the greatest load growth of all the regions over the next 10 years. This is due in large part to the expansion of the oilsands and secondary industries in the municipalities in the region. The current load in the Northeast region is predominantly industrial and makes up 2,349 MW, or 23 per cent of the 2010 AIL peak load. Load in the region is expected to grow to 4,078 MW in 2020, a significant increase from current levels.

Generation in the region is predominantly gas-fired generation at oilsands sites. There is currently 3,001 MW of generation capacity in the area, accounting for about 23 per cent of Alberta’s total installed generation capacity. Through the continued development of cogeneration at oilsands sites, generation capacity in the region is expected to increase to 4,865 MW by 2020. There is uncertainty surrounding the amount of cogeneration the industry will develop with their oilsands operations. Scenario and sensitivity studies were considered in Section 4.4.5 to address this uncertainty.

Current conditions Fort McMurray area – The majority of Northeast region growth is expected to occur in this area. Load growth is represented by major oilsands facilities that can be as high as 200 to 300 MW each. These proposed facilities are in pockets where oilsands development is expected to occur and are generally located:

n north of Fort McMurray

n northeast of Wabasca (Livock)

n west of Dover

n in the Christina Lake area

n in Algar-Kinosis (south of Fort McMurray).

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Figure 4.5.2.1-1: Existing Northeast transmission system

Northeast Load (MW) 2010 winter peak 2,349 2020 forecast winter peak 4,078

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

AURORA JOSLYN CREEK Firebag

DOVER

Fort McMurray

GREGOIRE

ALGAR KINOSIS

BRINTNELL MARIANA WABASCA

MCMILLAN CROW CONKLIN LEISMER

CHRISTINA LAKE

WINEFRED

FOSTER CREEK

HEART LAKE

WAUPISOO Lac La PRIMROSE Biche FLATBUSH FLAT LAKE MAHNO Athabasca MARGUERITE LAKE BOYLE COLINTON LACOREY

WHITEFISH LAKE Cold Lake Bonnyville

CLYDE LINDBERGH REDWATER Legal Elk Point SUBSTATIONS Existing transmission lines AMELIA 69 kV/72 kV 240 kV 138 kV/144 kV

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Cold Lake area – The 144 kV transmission system in this area is near capacity due to high generation currently flowing out of the area. In addition, new generation is expected to be connected in the northern part of the Cold Lake transmission system. Over the next 10 years loads in this area should absorb some of this generation and unload the transmission system. Regardless, new transmission facilities will be required to ensure supply can reach the new loads recognizing oilsands developers have the capability and the desire to deliver excess generation into the grid.

Athabasca/Lac La Biche area – The 138 kV transmission system in this area is near its capacity due to continuing load additions. Over the next 10 years, more pipeline pumping loads are expected that will cause both voltage and thermal violations throughout the local system.

Fort Saskatchewan area – Heavy oil upgrader projects are being proposed in the Fort Saskatchewan area. A 240 kV transmission system will be developed to deliver power to these loads. Associated load growth is anticipated for the 138 kV systems in support of upgrader projects.

4.5.2.2 Status of projects Conceptual plans have been developed for the four planning areas that comprise the Northeast region as described below.

Fort McMurray area Reactive power support is required in the Fort McMurray area to mitigate voltage fluctuations, transient swings and increased inertia of the larger Fort McMurray electrical system. These issues either individually or together can impact the stability of the transmission system. The reactive power project includes the addition of capacitor banks and reactive power devices at strategic substations. Also, under certain conditions the voltage on the easternmost 240 kV circuit to Fort McMurray can collapse. This problem can be mitigated in the short term by re-terminating the line that now goes from Whitefish to Leismer, in and out of Heart Lake. The stability and operational flexibility issues mentioned earlier can also be partially mitigated by interconnecting the east and central 240 kV supply lines with a short 240 kV line between Algar and Kinosis.

The current 240 kV line configuration north of Fort McMurray does not allow the flexibility necessary to ensure the system can be operated reliably. The Thickwood 240 kV switching station will provide that flexibility. This station will ultimately serve as the terminus for the proposed 500 kV circuits from Genesee and Heartland to Fort McMurray.

Continued load growth in the City of Fort McMurray requires additional supply to the city. The Salt Creek Project includes a 240/144 kV substation south of the city along with related 144 kV enhancements. This substation will also be the south terminal of the North of Fort McMurray 240 kV loop.

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There are several areas within the Northeast region that will see continued oilsands activity in the form of bitumen extraction, refining and pipeline facilities. These projects are driven by the need to connect large customer loads and include:

n The North of Fort McMurray area double circuit 240 kV loop from Joslyn Creek east and then south to a new substation (Salt Creek) near Fort McMurray to connect customers in that area.

n Livock 240/144 kV substation and related 144 kV lines will connect the initial large customer loads west and south of Fort McMurray.

n A 240/144 kV substation at Algar will alleviate the 144 kV system south of Fort McMurray currently operating at its design capacity.

n A 240 kV loop from Livock to Joslyn Creek will supply oilsands development in the area west and northwest of Fort McMurray.

n A 240 kV loop from Heart Lake to Christina Lake will connect the potential oilsands extraction facilities in the Christina Lake area.

Cold Lake area New 144 kV transmission facilities are required to mitigate overloads in the area as well as to accommodate the expected addition of new generation facilities and their associated loads. These enhancements are included in the Central East Transmission Development that is included as part of the Central region projects.

Athabasca/Lac La Biche area The area 138 kV transmission system will be strengthened by the addition of a new 138 kV circuit in the area to pick up additional pipeline loads.

Fort Saskatchewan area There is a need to reconfigure the 240 kV system in the Fort Saskatchewan area to provide increased operational flexibility. The first project consists of cutting one of the 240 kV circuits in and out at Josephburg substation and restoring the capacity limits on three of the 240 kV circuits. The second project driven in part by upgrader expansion includes a 240 kV transmission extension from the Heartland 500/240 kV substation.

Similar to the Northwest region, in addition to projects identified through the detailed system assessment process, it is expected that new distribution customer points of delivery (POD) will be requested. The need for these distribution PODs often surfaces in a very short (one to two year) timeframe. To respond to the uncertainty and yet acknowledge and assess these possibilities, this LTP includes the assumption that four such substations will be requested in the Northeast region in the next 10 years.

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4.5.2.3 Northeast region transmission projects Table 4.5.2.3-1: Northeast region transmission projects

year in C cost estimate service Project description (2011 $ millions) 2011 Athabasca Upgrade telecom in area $20 telecom upgrade 2012 9L66 240 kV line 9L66 240 kV line relocation $1 2012 Livock 240/144 kV substation and two $24 144 kV lines to customer facilities 2012 Northeast Capacitor banks at Dover, Whitefish $16 reactive and Leismer substations power 2012 Salt Creek 240 kV substation south of $30 Fort McMurray and 144 kV line to Hangingstone 2013 Fort Re-terminate 240 kV line in and $6 Saskatchewan out at Josephburg and increase near term rating on three 240 kV lines 2013 North of 240 kV double circuit line from $197 Fort McMurray Kearl Lake to Salt Creek and 240 kV switching stations at Kearl Lake and Black Fly 2015 Algar 240/144 kV substation tying adjacent $26 240 kV and 144 kV lines together 2015 Athabasca 240/138 kV transformer at Whitefish Lake $124 and 138 kV double circuit line to 794L (split 794L) and continue on to Boyle substation 2015 Christina 240 kV double circuit line from $350 Lake Heart Lake to a new 240/138 kV substation near Christina Lake 2015 Heart Lake Re-termination of the Whitefish- $8 Leismer 240 kV line in and out at Heart Lake 2015 Heartland Second 500/240 kV transformer at $69 240 kV Heartland and 240 kV double circuit second loop line to 942L tap between Lamoureux and Josephburg 2015 Thickwood 240 kV switching station northwest $173 of Fort McMurray and re-termination of four 240 kV lines in and out at Thickwood 2015-2020 Livock-Joslyn 240 kV double circuit $342 240 kV line from Livock to Joslyn 2020 Algar-Kinosis 240 kV line between Algar $61 and Kinosis substations 2011-2020 Distribution Four distribution substations $100 PODs Total $1,547

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4.5.2.4 Unique challenges, uncertainties and concerns The greatest uncertainty for regional transmission in the Northeast region is the speed at which the oilsands development will progress. The dates in Table 4.5.2.3-1 are based on customer connection requests. The potential for considerable expansion is seen in the area west and south of Fort McMurray as well as in the Christina Lake area. The LTP assumes expansion in these three areas; however, additional transmission reinforcement may be required if these areas grow to their full potential. If oilsands development slows, some of the transmission projects can be delayed. The AESO continues to monitor development to ensure transmission is in place ahead of need for customers to connect to the system.

The load and generation developments in the Northeast region are expected to generally balance each other. There is potential for the situation to rapidly swing from being balanced to turning into a load centre or supply area. Transmission thermal overloads and voltage fluctuations are a concern and transient swings and increased inertia of the larger Fort McMurray electrical system may also impact the stability of the transmission system. Stock photograph.

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4.5.3 Edmonton region 4.5.3.1 Overview The Edmonton region is located approximately in the centre of the AIES and includes the City of Edmonton and the Wabamun and Wetaskiwin areas. The region is bordered on the south by the Central region and on the north by the Northeast and Northwest regions. The Edmonton region is a major generation centre in the province. It is also the key hub for the transmission network connecting the northwest, northeast and south areas of the AIES bulk transmission systems through 240 kV lines.

The current Edmonton region system is comprised of transmission lines and substations that operate at 500 kV, 240 kV, 138 kV and 69 kV. Figure 4.5.3.1-1 shows the existing transmission system in this region.

Expected growth Load in the Edmonton region at the time of AIL peak is expected to grow from the 2010 actual of 2,093 MW to around 2,780 MW by 2020. This load growth generally comes from the residential and commercial load centres in Edmonton. As mentioned, the Edmonton region is a major generation centre in the province with 4,457 MW or 34 per cent of Alberta’s total installed generation capacity. Most of this generation capacity is baseload coal-fired plants located around Wabamun Lake.

Generation capacity in the area is expected to change over time with the potential for both retirement and addition of units. The aging coal-fired units in the area are expected to retire once they reach their end of life. Generation development in the region will be a function of response to new environmental standards, meaning that total generation may decrease or increase from the current level of 4,457 MW to between 4,385 MW and 5,420 MW. The noted change in the generation fleet includes the addition of Keephills 3 unit currently under construction and gas-fired capacity additions, specifically the potential repowering of brownfield sites in the Wabamun area with gas-fired combined cycle facilities.

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Figure 4.5.3.1-1: Existing Edmonton transmission system

Edmonton Load (MW) 2010 winter peak 2,093 2020 forecast winter peak 2,780

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

NORTH BARRHEAD Smoky Lake

Mayerthorpe REDWATER

SOUTH MAYERTHORPE LAC LA NONNE Bon Accord BEAMER DEERLAND Morinville Gibbons Bruderheim GLENEVIS Lamont

ONOWAY Fort Saskatchewan St. Albert Viscount WHITEWOOD MINE NAMAO Spruce Grove CELENESE ENTWISTLE WABAMUN Edmonton SUNDANCE YASA CARVEL BELLAMY Stony Plain BRETONA

DOME KEEPHILLS ELLERSLIE Tofield COOKING LAKE

GENESEE Beaumont Devon BARDO Calmar NISKU

BUFORD Leduc KINGMAN

Millet Camrose EAST CAMROSE BONNIEGLEN TRUWELD GRATING BIGSTONE ERVICK PIGEON LAKE WETASKIWIN

PONOKA NELSON LAKE SUBSTATIONS Existing transmission lines 69 kV/72 kV 240 kV 138 kV/144 kV 500 kV

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Current conditions The main source of electrical generation for the entire province is situated near Wabamun Lake in the Edmonton region. There is more than 4,000 MW of baseload generation connected to the AIES near Wabamun Lake to support various load centres, including Central and South Alberta loads, Northwest region loads, Edmonton area loads and major industrial loads located in the Fort Saskatchewan area. Generator instability and transmission overload limit transfers between Wabamun and Edmonton during peak load periods. Transfers from Wabamun south are also limited due to generator instability and transmission overloading.

There are major thermal overloads of transmission facilities throughout the Edmonton region. The 138 kV transmission paths from Wabamun to Edmonton, Edmonton to Leduc and from East Edmonton to the Fort Saskatchewan area are weak sections during peak load conditions. As well, most of the voltage violations occur in the Edmonton and Wetaskiwin areas due to weak system support. Within the City of Edmonton there are some thermal overload issues in the 72 kV system. Stock photograph.

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4.5.3.2 Status of projects The 2009 LTP included several upgrades to the 240 kV system between Wabamun and Edmonton as bulk system projects to alleviate system constraints in the region. Those upgrades are underway. In addition, a new 240/138 kV substation is proposed to reinforce the Wabamun area 138 kV supply by interconnecting to Acheson and Devon.

The existing lines in the North Calder, Viscount and St. Albert areas of the Edmonton region are overloaded under certain conditions. A new 138 kV line between Viscount and North Calder will address this issue.

Continued load growth in the Leduc area is resulting in the 138 kV system south of Edmonton being overloaded for various contingencies. A new 240/138 kV supply in the vicinity of Leduc will alleviate this problem. Overloading of these lines occurs when outages are experienced on the 240 kV lines south from the Edmonton region.

Low voltage in the Onoway area north of Wabamun Lake is a problem under certain conditions. This problem will be resolved with the addition of a capacitor bank at Onoway substation.

The cables that supply the Garneau substation in the University of Alberta area of the City of Edmonton are aging and need to be replaced. The plan is to replace the existing cables with new higher capacity cables.

With the anticipated retirement of Sundance 1 and 2 (576 MW coal) and their anticipated replacement with Sundance 7 (800 MW combined cycle), the net increase in generation cannot be moved out of the Sundance area with the current system. The proposal is to extend the Keephills-Ellerslie-Genesee (KEG) 500 kV loop from Keephills to Sundance. This extension requires about 12 km of new line and will strengthen the 500 kV loop to Ellerslie. The timing of this project will be driven by the timing of the addition of the Sundance 7 generation project.

Again, similar to the previous regions, in addition to projects identified through the detailed system assessment process, it is expected that new distribution customer points of delivery (POD) will be requested. The need for these distribution PODs often surfaces in a very short (one to two year) timeframe. To respond to the uncertainty and yet acknowledge and assess these possibilities, this LTP includes the assumption that four such substations will be requested in the Edmonton region in the next 10 years.

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4.5.3.3 Edmonton region transmission projects Table 4.5.3.3-1: Edmonton region current transmission projects

year in C cost estimate service Project description (2011 $ millions) 2012 Wabaumn- Complete the work which includes $153 Edmonton reconductoring one 240 kV lines, debottleneck re-terminating 240 kV lines on the Wabamun end and the Edmonton end, and adding a phase shifting transformer at Livock 2013 Garneau Replace underground cables $150 between Rossdale and Garneau 2013 Onoway Add 10 MVAr capacitor $3 bank at Onoway 2013 South of 240/138 kV substation near $57 Edmonton Nisku and 138 kV enhancements 2013 Southwest 240/138 kV substation near Edmonton Acheson and 138 kV enhancements $95 2014 North 138 kV line from North Calder $34 Edmonton to Viscount 2015-2017 Extend KEG 500 kV double circuit line from $119 loop to Keephills to Sundance and a Sundance 500/240 kV substation at Sundance 2011-2020 Distribution Four distribution substations $100 PODs Total $711

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4.5.3.4 Unique challenges, uncertainties and concerns The Edmonton region is a major corridor for electricity flows between the Northeast, Central and South regions. The power requirements of the major oil production facilities in the Northeast region can have a significant impact on transmission infrastructure in the Edmonton region. The retirement of coal-fired generation facilities and possible replacement with combined cycle generation could impact the flows through and out of this region.

The City of Edmonton transmission network consists primarily of a 72 kV system made up of high pressure oil-filled pipe type cables servicing 72 kV to 15 kV bulk-type substations, all of which are nearing (or in some cases beyond) their life expectancy. A near-term goal will be to determine if the 72 kV voltage level is still appropriate for the service expected. It will also be necessary to determine if the existing cable technology – oil-filled pipe type cable – is still appropriate, and what changes and upgrading are required to the Edmonton substations to modernize and service increasing load and load densities. Photo courtesy of EPCOR Utilities Inc.

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4.5.4 Central region 4.5.4.1 Overview The Central region spans the province east to west between Edmonton and Calgary. The major transmission facilities of the Central region are shown in Figure 4.5.4.1-1.

Expected growth Electricity demand in the Central region at the time of AIL peak is expected to grow from 1,505 MW in 2010 to 2,251 MW in 2020. This load growth generally comes from pipeline and industrial activity in the region as well as residential and commercial expansion in Red Deer. The east side of the Central region is a major path for pipelines between Edmonton and the Northeast region, as well as to other markets. The increase in load in the region is partly a function of the planned expansion in this pipeline corridor.

Current generation capacity in the region totals 1,837 MW. The generation is a mix of hydro, coal-fired and industrial gas-fired cogeneration. Generation resources available for development in the region include gas, wind, hydro and coal. Generation capacity in the region is expected to increase to between 2,130 MW and 2,630 MW by 2020, with the additions being primarily gas-fired capacity and wind generation. A number of wind projects in the Central region totalling over 1,200 MW have applied for connection to the grid. The Battle River units 3 and 4 are expected to retire prior to 2020 following the expiration of the Power Purchase Arrangements in 2013, offsetting some of the new generation additions in the area.

Current conditions With its location in the middle of Alberta, there is a significant transfer of energy through this region on the north to south path between Edmonton and Calgary on the existing 240 kV system.

Hanna and Wainwright areas One of the key drivers for load growth in the Wainwright and Hanna areas is the projected building of a number of new pipelines for carrying bitumen and oil products from oilsands projects to markets in the U.S. and other proposed destinations.

In addition to load, the AESO has received system access service applications for the connection of close to 1,200 MW of wind generation projects in the Central region as of April 30, 2011. The majority of the build is anticipated in the Hanna area. This area includes coal-fired generation at Battle River and Sheerness. As generation in the area increases, it results in a generator instability limit on the 240 kV circuits going south from Sheerness.

Red Deer and Didsbury areas Load growth in the Red Deer and Didsbury areas will result in overloading the existing 138 kV system. In addition, there is an operational constraint associated with the Joffre generation due to limited capacity on the 138 kV transmission system. Thermal line loading limits transfers in and out of Joffre under certain load and generation conditions.

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Figure 4.5.4.1-1: Existing Central transmission system

Central Load (MW) 2010 winter peak 1,505 2020 forecast winter peak 2,251

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

VILNA ST. PAUL

MARLBORO IRISH CREEK WILLINGDON Two Hills BICKERDIKE PINEDALE Edson Vegreville Hinton DALEHURST Vermilion FICKLE LAKE Watson Creek Drayton Lloydminster GULF ROBB Valley NORTH HOLDEN COLD CREEK Briker Cheviot COAL VALLEY LODGEPOLE BUFFALO CREEK CARDINAL RIVER CADOMIN BRAZEAU STROME Wainwright BUCK LAKE ELK RIVER Killam BRAZEAU EDGERTON ASTORIA RIVER SEDGEWICK WILLESDEN GREEN HEISLER HARDISTY METISKOW HAYTER Rocky Lacombe CORDEL Mountain NEVIS ECKVILLE SUNKEN LAKE House Sylvan L. Stettler BIGFOOT Provost BIGHORN PLANT BENALTO DELBURNE STETTLER Castor Ribstone Creek STRACHAN Red Deer BIG VALLEY Coronation MONITOR SULLIVAN L. VETERAN SUNDRE LIMESTONE ROWLEY Didsbury Hanna HARMATTAN Three Hills RICHDALE

Drumheller Oyen

SUBSTATIONS Existing transmission lines 69 kV/72 kV 240 kV 138 kV/144 kV

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Central East and Central West areas The central east area is approximately between Cold Lake and Vermilion and east of Edmonton. The central west area includes Wabamun Lake-Drayton Valley and extends west to Edson-Hinton. Improvements are required in part to supply general area load increases and to replace aging facilities. Although the Cold Lake area is part of the Northeast region, enhancements to support Cold Lake have been included in the central east area.

4.5.4.2 Status of projects Transmission development is required in the Red Deer area to meet projected load growth. These enhancements include three 240/138 kV substations in the area as well as several 138 kV transmission line upgrades.

The plan for the Hanna area was developed to meet the additional pipeline loads and wind generation and convert parts of the aging 69 kV and 72 kV systems to 138 kV. To accommodate the pipeline loads, the plan is to construct a 240 kV loop from Anderson to Metiskow with two new 240/144 kV substations between Oyen and Metiskow. The aging 69/72 kV system will be enhanced with 138 kV lines and substation upgrades as well as the addition of capacitor banks and reactive power devices for voltage support. Wind integration will require the construction of a new double circuit 240 kV line and a substation west of Anderson (in the South region). Besides supplying pipeline loads, the Hanna area project will also relieve a constraint south of the Sheerness generation facility. The 240 kV loop between Anderson and Metiskow will be constructed in two stages. The first will include double circuit towers with one side strung; stage two will string the second side of the towers.

In addition to the larger Hanna project, the LTP identifies a need to convert some of the aging 69 kV and 72 kV systems to 138 kV in the north of the region near Stettler and in the south of the region near Oyen by 2020.

Aging infrastructure, overloads and low voltages in the central east area of the province (the large area east of Edmonton from Cold Lake in the Northeast region to Hardisty) requires a substantial rebuild of the 138 kV and 144 kV systems as well as decommissioning of aging 69 kV and 72 kV lines. The central east project includes multiple 138 kV upgrades to meet the needs of this area of the province.

Similar to the central east area, the central west area also has aging infrastructure, overloads and low voltage conditions. This area extends from Wabamun and Drayton Valley in the Edmonton region to Hinton in the west. Enhancements to the 138 kV system and reconfiguration in the Edson-Hinton area, as well as replacement of aging 69 kV circuits in the Wabamun-Drayton Valley area, will relieve the system overloads and low voltage conditions.

In addition to projects identified through the detailed system assessment process, it is expected that new distribution customer points of delivery will be requested. The need for these distribution PODs often surfaces in a very short (one to two year) timeframe. To respond to the uncertainty and yet acknowledge and assess these possibilities, this LTP includes the assumption that four such substations will be requested in the Central region in the next 10 years.

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4.5.4.3 Central region transmission projects Table 4.5.4.3-1: Central region current transmission projects

year in C cost estimate service Project description (2011 $ millions) 2011-2012 Yellowhead Conversion of the 69 kV systems $123 to 138 kV from Wabamun to Drayton Valley and Wabamun to Barrhead; reconfiguration and enhancements to the 138 kV system in the Edson-Hinton area 2012-2014 Central East Extensive enhancements and $352 reconfiguration of the 138 kV and 144 kV systems east of Edmonton between Cold Lake and Hardisty 2012-2017 Red Deer Three 240/138 kV substations near $204 area Ponoka, Innisfail and Didsbury; major reconfiguration of the 138 kV system in and around the city of Red Deer 2014-2017 Hanna area A new 240/144 kV substation $909 near Hardisty with a 240 kV double circuit line connecting the new substation to the 240 kV line between Cordel and Hansman Lake; a 240 kV double circuit line from Anderson to Oyen and north to Hansman Lake with a new 240 kV SW 2018 Hanna 69 kV Conversion of parts of the 69 kV systems $66 near Stettler and Oyen to 138 kV 2011-2020 Distribution Four distribution substations $100 PODs Total $1,754

4.5.4.4 Unique challenges, uncertainties and concerns The major driver for transmission development in the Central region is the anticipated expansion of the pipeline corridor from Edmonton and the Northeast region through the east side of the province and on to markets in the U.S. The speed at which new pipelines are added could impact the timing of the Hanna area development. There is also potential for substantial wind development east of Highway 2 between Edmonton and Calgary. This wind generation could have an impact on the need and timing of 240 kV enhancements in the Central region and between the Central region and other regions.

An intertie to Saskatchewan at Lloydminster is being proposed as a merchant facility. Depending on the size of this intertie, additional transmission reinforcement in the central east area might be required.

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4.5.5 South region 4.5.5.1 Overview The South region of Alberta has as its south boundary the Canada-U.S. border. The region is bordered on the north by the Central region and includes Calgary and the surrounding area. The region is also bordered by B.C. and Saskatchewan on the west and east respectively. The major transmission facilities of the South region are shown in Figure 4.5.5.1-1.

Expected growth The South region is a major load centre in Alberta. Large load centres within the region include Calgary, Lethbridge, Medicine Hat and the Empress industrial area. The region’s load at the time of system peak was 2,917 MW in 2010, or 29 per cent of the province’s peak. By 2020 load is expected to increase to 4,093 MW. This load growth comes mainly from general growth in the industrial, residential and commercial sectors, and considers some pipeline expansion as well.

The region currently contains 2,919 MW of Alberta’s total installed generation capacity, made up of a mix of hydro, coal-fired, gas-fired and wind. Currently, the majority (695 MW) of the province’s 777 MW of transmission connected wind capacity is located in this region. Generation development potential in the region consists mainly of gas-fired and wind facilities. The AESO has received system access for a significant number of wind generation projects in the South region, with 5,500 MW of the total 6,700 MW in the connection queue. Generation capacity in the region is expected to increase to between 4,955 and 6,000 MW with the main additions again being gas-fired and wind generation facilities.

Current conditions The region has historically been a net importer of power from the rest of the AIES even though the non-coincident peak load in the region is less than its generating capacity. The amount of power flowing into the region depends on the output of wind generation in the region, which is intermittent. The region has typically imported about five per cent of its annual energy supply, which indicates it has almost enough generation to supply its own load.

The portion of the generation produced by wind generating facilities located in the South region is expected to increase substantially over the next five years. Energy production from these facilities will vary based upon the available wind to drive the turbines. During certain wind conditions, the South region will have a surplus of power to deliver to the rest of Alberta and export to B.C. and Saskatchewan through transmission interties.

The Calgary area is a major load centre for this region and the province with close to 25 per cent of Alberta’s total load requirement. TMR generation is required depending on the availability of transmission system elements. The need to periodically call upon TMR generation indicates that the transmission system is not adequate to serve the current load. TMR payment represents costs to consumers that an investment in transmission would avoid.

The City of Calgary and the surrounding area continue to see increased demand as the population continues to grow. Along with additional distribution growth, the bulk 240 kV network that supplies power to the PODs will also require upgrades to keep pace with the strong and steady growth in demand.

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Figure 4.5.5.1-1: Existing South transmission system

South Load (MW) 2010 winter peak 2,917 2020 forecast winter peak 4,093

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

SHEERNESS ANDERSON LAKE LOUISE WEST CROSSFIELD

EAST AIRDRIE HORSE CREEK Airdrie GHOST BANFF BEDDINGTON COCHRANE BULLPOUND SPRAY Strathmore LAKES SEEBE NAMAKA Canmore BARRIER JANET SPRINGBANK LANGDON HUSSAR CALGARY WARE JUNCTION WARDLOW THREE SISTERS CARSELAND GLEICHEN EMPRESS DUCHESS OKOTOKS JENNER POCATERRA Black Diamond MCNEILL MAGCAN Turner Valley Brooks HARTELL BLACKIE QUEENSTOWN HIGH RIVER WEST BROOKS TILLEY

Nanton VULCAN ENCHANT SUFFIELD

EAST STAVELY CHAPPICE LAKE Stavely VAUXHALL Medicine Hat HAYS Redcliff BULLSHEAD Claresholm Picture Butte Bow Island Granum MONARCH BURDETT PEACE BUTTE RANGE PIPE TABER FINCASTLE LUNDBRECK FORT MACLEOD Hillridge COALBANKS Lethbridge WESTFIELD PEIGAN CHIN CHUTE COLEMAN MCBRIDE LAKE BOWRON IRRICAN POWER STIRLING Crowsnest CONRAD Pass Raymond GLENWOOD Magrath Cardston RAYMOND WARNER RESERVOIR Milk River WATERTON DRYWOOD SPRING ST. MARY COULEE HYDRO

SUBSTATIONS Existing transmission lines 69 kV/72 kV 240 kV 138 kV/144 kV 500 kV

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Issues identified The existing 240 kV and 138 kV system in the south is inadequate to support anticipated wind generation development in this region. Recent enhancements, which include a 240 kV double circuit line from Pincher Creek to Lethbridge, will help integrate wind; however, it is not sufficient to meet anticipated wind development to 2020.

In addition to wind integration, load related thermal overloads and voltage violations were identified in the Glenwood area in the southernmost part of the system from Waterton to Stirling.

Thermal overloads and low voltages were identified in most of the region from Airdrie through to the City of Calgary and south to High River in the 2015 and 2020 timeframe.

4.5.5.2 Status of projects Continued load growth north of Calgary will result in overload and low voltage conditions on the 138 kV system in that area. The preferred enhancement includes a 240/138 kV substation east of Airdrie and local area 138 kV enhancements.

Parts of the transmission system within the city of Calgary are nearing the end of their operating life. Also, increased loading on older 69 kV systems results in system overloads and low voltages under certain conditions. This LTP defines several system enhancement projects along with the replacement of aging infrastructure in order to upgrade the system:

n Replacement of the underground cables connecting downtown Calgary substations.

n Addition of 138 kV circuits and conversion of older 69 kV substations in south Calgary to replace the aging 69 kV system.

n Addition of 138 kV circuits and conversion of older 69 kV substations in north Calgary to replace the aging 69 kV system.

As Calgary continues to expand to the north and west, there will be a need for a 240 kV supply in these areas. This supply is expected to be required sometime in the next 10 to 15 years.

To accommodate load growth and resolve voltage issues in the High River-Black Diamond area, a new 138 kV line will be required from the proposed High River area 240/138 kV substation and new Big Rock substation on to the Black Diamond substation.

The aging 69 kV system south of Highway 3 between Pincher Creek and Lethbridge is reaching the end of its operating life and is subject to overloads and low voltages under certain conditions. The recommended enhancement is to gradually replace the 69 kV system with a 138 kV system.

High wind development north of Pincher Creek requires the installation of a 240 kV substation to tie wind generators to the grid.

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In addition to projects identified through the detailed system assessment process, it is expected that new distribution customer points of delivery will be requested. The need for these distribution PODs often surfaces in a very short (one to two year) timeframe. To respond to the uncertainty and yet acknowledge and assess these possibilities, the LTP includes the assumption that four such substations will be requested in the South region in the next 10 years.

4.5.5.3 South region transmission projects Table 4.5.5.3-1: South region current transmission projects

year in C cost estimate service Project description (2011 $ millions)

2011 Calgary Replace existing 138 kV cables $66 downtown with higher capacity 138 kV cables cable replacement 2012 Fidler Fidler 240 kV substation $35 2013 Calgary Convert 69 kV system in south Calgary to $23 South 69 kV 138 kV and salvage part of the old system conversion 2015 Airdrie area 240/138 kV substation east of Airdrie $28 and a 138 kV double circuit line to connect to the existing 138 kV system 2013-2015 North Convert 69 kV system to 138 kV and $150 Calgary 69 kV salvage parts of the 69 kV system conversion 2016 Big Rock 138 kV line from Okotoks to Big Rock $24 to Black Diamond and salvage 69 kV line from High River to Black Diamond 2016 South Convert 69 kV to 138 kV from Pincher $48 Alberta 69 kV Creek to Cowley and from Stirling conversion to Magrath 2011-2020 Distribution Four distribution substations $100 PODs

Total $475

4.5.5.4 Unique challenges, uncertainties and concerns The largest planning challenge for the South region is the amount of wind generation that has requested to be connected to the AIES. This is being addressed by the SATR development, applying project staging and setting milestones for when various transmission components are needed.

Generation development, both wind in the south and gas-fired generation in and around Calgary, can impact the Foothills Area Transmission Development (FATD) project. The timing of the west leg from Foothills substation to Sarcee substation is dependent on where and when these forms of generation develop.

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4.6 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.

Figure 4.6-1: Projects by development stages and respective cost estimate accuracy $10,000

$9,000 + 50% $8,000

$7,000 + 20%

$6,000

$5,000 - 10% + 30% 2011 $ millions $4,000

$3,000 + 50% $2,000 - 30%

$1,000

$0 Facility Application Need Identification Document Planning

Range in the accuracy of the cost estimate

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The estimates of the capital costs and timing of the projects in this LTP were prepared or confirmed in late 2010 and early 2011. Costs and timing are expected to change over time as projects are more fully developed, as the factors affecting transmission requirements change and evolve, and as the LTP is updated and revised. Updates to costs and timing of projects are provided to stakeholders in AESO quarterly reports, also in accordance with ISO Rule 9.1 on transmission facility projects.

Significant estimating uncertainty results from how far in the future the project is needed. For example, the cost estimates for projects needed post 2020 are difficult to prepare given that no dependable cost data for labour or commodity pricing is available at this time. Because of this, the cost estimates for these projects are not shown. In addition, the scope definition of many of these projects is subject to further development as more definitive information associated with load and generation become available. The cost estimates of these projects will be included in future updates of the LTP.

In addition to reporting on the quarterly project cost updates for projects in the NID or FA stages (posted to the AESO website) and to provide more useful and up-to-date information to stakeholders, for this LTP the AESO has summarized costs and timing of projects in this section as well as in a separate Transmission Rate Impact Analysis posted on our website. The AESO will regularly update the Transmission Rate Impact Analysis to reflect changes to the capital costs and timing of projects identified in this LTP, including the most recent estimate of the impact of those costs on transmission rates. The most recent update of the Transmission Rate Impact Analysis is available on the AESO website at www.aeso.ca

4.6.1 Project cost estimates Table 4.6.1-1 provides the cost estimate, timing, and estimate class for each project included in this LTP. The projects are grouped geographically and listed in the same order as in previous sections. Cost estimates are in 2011 dollars and include costs generally incurred by TFOs such as engineering and supervision, allowance for funds used during construction (AFUDC), distributed general and administrative costs, and contingencies. As the cost estimates are in 2011 dollars, inflation may result in costs increasing when the projects are placed in service and included in the rate base of TFOs. The impact of inflation is estimated in the transmission rate impact analysis that follows in Section 4.6.2.

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Table 4.6.1-1: Projected cost estimates and timing: 2011-2020

Y year in Cost estimate cost estimate Project description service (2011 $ millions) class Bulk transmission system projects (including Critical Transmission Infrastructure (CTI)) South Calgary source (CTI) 2012 $37 FA Heartland 500 kV (CTI) 2013 $537 FA East HVDC (CTI) 2014 $1,622 FA West HVDC (CTI) 2014 $1,329 FA Bickerdike – Little Smoky 2015 $205 Planning West Fort McMurray 500 kV (CTI) 2017 $1,649 Planning 9L15 retermination at Livock 2017 $40 Planning South Area Transmission Reinforcement (SATR) 2011-2017 $2,287 NID Foothills Area Transmission Development (FATD) 2014-2017 $711 Planning Bulk transmission system projects subtotal – $8,417 – northwest region North Central 2013 $65 FA Otauwau – Slave Lake 2014 $18 Planning Grande Prairie 2015 $287 Planning Hotchkiss reactive support 2015 $6 Planning H.R. Milner connection 2015-2018 $164 Planning Distribution points of delivery 2011-2020 $100 Planning northwest region projects subtotal – $640 – northeast region Athabasca telecom upgrade 2011 $20 FA 9L66 240 kV line relocation 2012 $1 FA Livock 2012 $24 FA Northeast reactive power 2012 $16 FA Salt Creek 2012 $30 FA North of Fort McMurray 2013 $197 FA Fort Saskatchewan near-term 2013 $6 Planning Algar 2015 $26 Planning Athabasca 2015 $124 Planning Christina Lake 2015 $350 Planning Heart Lake 2015 $8 Planning Heartland 240 kV second loop 2015 $69 Planning Thickwood 2015 $173 NID Livock – Joslyn 240 kV 2015-2020 $342 Planning Algar – Kinosis 2020 $61 Planning Distribution points of connection 2011-2020 $100 Planning northeast region projects subtotal – $1,547 –

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Y year in Cost estimate cost estimate Project description service (2011 $ millions) class Edmonton region Wabamun – Edmonton debottleneck 2012 $153 FA Garneau 2013 $150 Planning Onoway 2013 $3 Planning South of Edmonton 2013 $57 Planning Southwest Edmonton 2013 $95 Planning North Edmonton 2014 $34 Planning Extend KEG loop to Sundance 2015-2017 $119 Planning Distribution points of delivery 2011-2020 $100 Planning Edmonton region projects subtotal – $711 – central region Yellowhead 2011-2012 $123 FA Central East 2012-2014 $352 NID Red Deer area 2012-2017 $204 NID Hanna Area Transmission Development (HATD) 2014-2017 $909 FA Hanna 69 kV 2018 $66 Planning Distribution points of delivery 2011-2020 $100 Planning central region projects subtotal – $1,754 – South region Calgary downtown cable replacement 2011 $66 FA Fidler 2012 $35 FA Calgary South 69 kV conversion 2013 $23 FA Airdrie area 2015 $28 FA North Calgary 69 kV conversion 2015 $150 Planning Big Rock 2016 $24 Planning South Alberta 69 kV conversion 2016 $48 Planning Distribution points of delivery 2011-2020 $100 Planning South region projects subtotal – $475 – total, all projects 2011-2020 $13,545 –

Note: Totals and subtotals may differ due to rounding

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.

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This Plan also discusses some projects that occur after the 2011-2020 period included in Table 4.6.1-2. Two CTI projects were included in the 2009 LTP and have now been deferred beyond 2020. A new project, North Calgary 240 kV supply, has also been identified for the post-2020 period.

Table 4.6.1-2: Projects with in-service dates beyond 2020

Project Year in service

North Calgary 240 kV supply 2021 CTI: East Fort McMurray 500 kV 2021-2022 CTI: increase capacity of both 500 kV HVDC lines Post 2020

Table 4.6.1-3: LTP capital cost summary by region

region Estimated cost (2011 $ millions)

CTI total $5,174 HVDC $2,951 Heartland $537 Fort McMurray $1,649 Calgary $37 South $3,473 Central $1,754 Edmonton $711 northeast $1,588 Northwest $845 AIES total $13,545

4.6.2 Transmission rate impact Transmission facility owners (including both owners of existing regulated transmission facilities and of future facilities resulting from a competitive process) will build, own, operate and maintain the projects included in the LTP. The AESO pays owners for the use of their facilities and recovers those costs through regulated rates charged for system access service. Payments to the AESO for system access service are included in the transmission charges on bills for electric service paid by all end-use consumers, whether industrial, commercial, residential or farm.

The total cost of all transmission projects in this LTP is recovered over the life of the transmission facilities, which typically last 40 or more years. Not all projects are built at the same time and the impact of the projects in this LTP on customer rates will occur gradually as they are placed in service over the years 2011 to 2020.

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In some cases, new transmission projects will reduce operating and maintenance costs associated with older transmission facilities that are being replaced and/or removed. Additional capacity resulting from new projects will allow flexibility in operation and permit optimal management of the transmission system.

The transmission projects in this LTP will have other impacts on the costs of electric service. For example, they will improve the efficiency of the transmission system and reduce system losses. The transmission projects will also reduce costs resulting from transmission system congestion that can prevent the operation of the most economical generation.

It is challenging to accurately determine the rate impact of the transmission projects, given the various factors mentioned above and the changes to project cost estimates and timing. To provide up-to-date information to stakeholders, the AESO has developed a rate impact model for the Long-term Transmission Plan in working Microsoft Excel format on our website. The model is updated regularly, and the current version is available at www.aeso.ca

Based on current transmission costs, the costs estimates and timing provided in Table 4.6.1-1, and forecasts of increased volumes for system access service, the AESO estimates that transmission costs will gradually increase up to $19/MWh (1.9¢/kWh) over the years covered in this LTP. This would increase the electric bill for an average residential consumer (using 600 kWh/month) by $11 per month from about $92 per month in 2011 to about $103 per month in 2020. These estimates hold other costs constant and do not include increases due to escalation of those other costs.

Similarly, for an average industrial customer, (80 per cent load factor), the average charge for a megawatt of delivered power would increase from about $79/MWh in 2011 to about $98/MWh in 2020.

The transmission rate impact analysis and related information on the AESO website provide additional information on the cost estimates and timing of projects and will be regularly updated. As well, the analysis provides a calculator to estimate the increase in electricity costs for an individual industrial or residential service, due to the impact of the transmission projects in the LTP. The model and calculator allow different assumptions to be modified so that users may assess the sensitivity of the analysis to different factors.

The impact analysis summarized in this section is based on cost estimates and timing of transmission projects in the LTP and assumptions about other factors, all of which were established in early 2011. Please refer to the most recent Transmission Rate Impact Analysis for current information.

4.0 AESO Analysis and Planning Results PAGE 133 AESO Long-term Transmission Plan

Figure 4.6.2-1: Transmission cost impact on residential and industrial customers Residential $120

$100 $21/month Transmission $9/month

$80

$60

Energy, distribution and retail $40 Average residential bill ($/month) residential Average

$20

$0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Energy, distribution and retail Transmission

Industrial $120

$100

$35/MWh $80 Transmission $16/MWh

$60

$40 Energy Average industrial charges ($/MWh) industrial charges Average

$20

$0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Energy Transmission

PAGE 134 4.0 AESO Analysis and Planning Results AESO Long-term Transmission Plan

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.

Figure 4.6.3-1: Reconciliation of this LTP and 2009 LTP costs $16,000

$14,000 1,927 Scope change 1,473

$12,000 1,520 New 1,122 1,281 1,216 $10,000

$8,000 14,463 $ millions 13,545

$6,000 10,951

$4,000

$2,000

$0 2009 LTP Projects Projects Projects Escalation Adjusted New projects This LTP (2008 $) cancelled delayed completed 2008 to 2011 2009 LTP and scope (2011 $) (2008 $) beyond 2020 or near (2011 $) (2011 $) changes (2008 $) completion (2011 $) (2008 $)

4.0 AESO Analysis and Planning Results PAGE 135 AESO Long-term Transmission Plan

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

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

PAGE 136 4.0 AESO Analysis and Planning Results AESO Long-term Transmission Plan

Table 4.6.3-5: New projects in this LTP

Estimated cost Region Project Description ISd driver (2011 $ millions) South Fidler Fidler 240 kV substation 2012 Reliability and wind $35 Airdrie 240 kV and 138 kV enhancements 2015 Load and reliability $28 North Calgary – Local area 138 kV enhancements Load, aging $150 stage 1 and 69 kV conversion 2015 infrastructure, reliability Central Hanna 69 kV Convert local area transmission from 2018 Aging $66 69 kV to 138 kV infrastructure and load Edmonton Garneau Upgrade the 72 kV network in 2013 Aging $150 Garneau/Meadowlark area infrastructure and reliability Onoway upgrade Add reactive support 2013 Load $3 Extend KEG 500 kV interconnection to Sundance 2015-2017 Generation $119 500 kV interconnection Northeast Athabasca Upgrade telecom in area 2011 Reliability $20 telecom and operations upgrade 9L66 240 kV line 9L66 240 kV line relocation 2012 Load $1 Northeast Capacity banks at various substations 2012 Reliability $16 reactive power reinforcement Fort Saskatchewan 240 kV enhancements 2013 Reliability $6 (near-term) Algar substation New 240/138 kV substation at Algar 2015 Load $26 9L30 in/out at Terminate 9L30 (Whitefish-Leismer) 2015 Reliability $8 Heart Lake in/out at Heart Lake Re-terminate Re-terminate east end of 9L15 2017 Reliability and load $40 east end of 9L15 (Brintnell-Wesley Creek) 240 kV line from Brintnell to Livock Algor-Kinosis 240 kV double circuit Algor-Kinosis 2020 Load $61 Northwest Otauwau/ 144 kV line from Otauwau to Slave Lake 2014 Reliability $18 Slave Lake and transformer upgrade Bickerdike to 240 kV double circuit from 2015 Reliability $205 Little Smoky Bickerdike to Little Smoky Hotchkiss Reactor banks addition 2015 Reliability $6 reactor banks Milner 240 kV 240 kV double circuit from Milner 2015-2018 Generation $164 interconnection to new Wembley substation interconnection near Grande Prairie Total $1,122

4.0 AESO Analysis and Planning Results PAGE 137 AESO Long-term Transmission Plan

Table 4.6.3-6: Projects in the 2009 LTP with scope changes included in this LTP

A adjusted cost for Estimated cost project in 2009 LTP of this LTP Region Project (2011 $ millions) (2011 $ millions) CTI East HVDC (CTI) $1,462 $1,622 Heartland 500 kV (CTI) $495 $537 South Calgary source (CTI) $112 $37 West Fort McMurray 500 kV (CTI) $1,378 $1,649 West HVDC (CTI) $1,277 $1,329 Northwest Grande Prairie $193 $287 North Central $56 $65 Distribution points of delivery $0 $100 Northeast Athabasca $38 $124 Christina Lake $253 $350 Heartland 240 kV second loop $247 $69 Livock $22 $24 Livock – Joslyn 240 kV $157 $342 North of Fort McMurray $354 $197 Salt Creek $34 $30 Thickwood $0 $173 Distribution points of delivery $112 $100 Edmonton North Edmonton $62 $34 South of Edmonton $54 $57 Southwest Edmonton $56 $95 Wabamun – Edmonton debottleneck $137 $153 Distribution points of delivery $169 $100 Central Central East $359 $352 Hanna Area Transmission Development (HATD) $564 $909 Red Deer area $92 $204 Yellowhead $88 $123 Distribution points of delivery $94 $100 South Big Rock $57 $24 Calgary downtown cable replacement $22 $66 Calgary South 69 kV conversion $25 $23 Foothills Area Transmission Development (FATD) $619 $711 South Alberta 69 kV conversion $147 $48 South Area Transmission Reinforcement (SATR) $2,142 $2,287 Distribution points of delivery $70 $100

Totals $10,951 $12,423 net difference $1,473

PAGE 138 4.0 AESO Analysis and Planning Results 5.0 Conclusion

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 139 AESO Long-term Transmission Plan

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. AESO file photograph.

PAGE 140 5.0 Conclusion