AESO 2014 Long-term Outlook

The information contained in this document is published in accordance with the AESO s legislative obligations and is for information purposes only. As such, the AESO makes no warranties or representations as to the accuracy, completeness or fitness for any particular purpose with respect to the information contained herein, whether express or implied. While the AESO has made every attempt to ensure information is obtained from reliable sources, the AESO is not responsible for any errors or omissions. Consequently, any reliance placed on the information contained herein is at the reader s sole risk.

Table of Contents 1.0 Executive Summary 1 1.1 AESO Scenarios 3 1.2 Forecast Results 3 2.0 Introduction 4 2.1 Overview of the Forecast Process 5 3.0 Economic Outlook 8 3.1 Introduction 8 3.2 Economic Outlook 8 3.3 Energy Commodity Outlook 11 4.0 Environmental Drivers 12 4.1 Introduction 12 4.2 Coal-fired Generation of Electricity Regulations 12 4.3 Specified Gas Emitters Regulation 13 5.0 Provincial Outlook 14 5.1 Introduction 14 5.2 Energy & Load 15 5.3 Generation 16 6.0 Regional Outlooks 17 6.1 Introduction 17 6.2 Northeast Region 18 6.2.1 Load 18 6.2.2 Generation 19 6.3 Northwest Region 20 6.3.1 Load 20 6.3.2 Generation 21 Table of Contents

6.4 Edmonton Region 22 6.4.1 Load 22 6.4.2 Generation 23 6.5 Central Region 24 6.5.1 Load 24 6.5.2 Generation 24 6.6 South Region 26 6.6.1 Load 26 6.6.2 Generation 26 6.7 Outlook Summary and Risks 27 6.7.1 Load Risks 28 6.7.2 Generation Risks 29 7.0 Scenarios 30 7.1 Purpose 30 7.2 Methodology and Drivers 31 7.2.1 Scenarios Drivers 31 7.2.2 Oilsands Production and Load 31 7.2.3 Environmental Policy 31 7.2.4 Technology Advances 31 7.2.5 Other Drivers 32 7.3 Low Growth Scenario 32 7.3.1 Low Growth Scenario Provincial Outlook 32 7.4 Environmental Shift Scenario 33 7.4.1 Environmental Shift Provincial Outlook 33 7.5 Energy Transformation Scenario 35 7.5.1 Energy Transformation Provincial Outlook 35 7.6 2014 LTO Results Summary and comparison 36 Appendix A Main Outlook Detailed Results 38 Appendix B Forecasting Process 40 Appendix C Forecast Considerations 41 Appendix D Forecast Comparison 66 Appendix E System Load 68 Appendix F Industry Engagement 71 Appendix G Alberta Reliability Standard Requirements 72 Appendix H Glossary of Terms 74 Table of Contents

1.0 Executive Summary The 2014 Long-term Outlook (2014 LTO) is the Alberta Electric System Operator s (AESO) long-term forecast of Alberta s expected future demand and energy requirements over the next 20 years, along with the expected generation capacity to meet those requirements. The AESO s Long-term Outlooks describe the methodology, assumptions and results that serve as key inputs to the AESO s long-term transmission planning process, and ultimately the publication of the Long-term Transmission Plan for Alberta. The 2014 LTO is also used as an input into many of the AESO s core business activities, including transmission system development, system operations, customer access and market services. The 2014 LTO is prepared in accordance with the duties of the AESO as outlined in Alberta s Electric Utilities Act (EUA) and the Transmission Regulation (AR 86/2007), and will be used to support Needs Identification Document (NID) filings that may be submitted to the Alberta Utilities Commission (AUC). The Long-term Outlook is the starting point for the AESO s transmission planning process cycle which includes the creation of the Long-term Transmission Plan (LTP) and Regional Plans. Transmission connection studies also rely upon the 2014 LTO s load and generation forecasts. The LTP is a blueprint for ensuring the Alberta Interconnected Electric System (AIES) continues to meet the province s future electricity needs and support the fair, efficient and openly competitive operation of the electricity market. Stock Photograph. 1.0 Executive Summary PAGE 1

As part of its forecast process, the AESO compared the 2014 LTO to past forecasts including the 2012 Long-term Outlook (2012 LTO) and 2012 Long-Term Outlook Update (2012 LTOU). Differences in forecast demand and generation were analyzed to determine if there were material impacts which could affect previously planned transmission facilities. Overall, the 2014 LTO is very similar to the 2012 LTOU. In most instances, changes in the 2014 LTO from the 2012 LTO and 2012 LTOU were already studied as sensitivities in transmission plans because potential major impacts were the result of load and generation project changes. The 2014 LTO includes a 20-year peak demand and electricity consumption forecast and a generation capacity projection for Alberta. The forecast s foundation is an economic outlook which considers global, U.S., Canadian and provincial factors that affect Alberta s economy. The 2014 LTO economic outlook assumes that throughout the forecast and especially over the next five to 10 years, global demand for crude oil will sustain prices and support strong investment in the oilsands, which will also drive strong Alberta economic growth. This economic outlook is verified against other third-party economic forecasts. Expansion of the oilsands will have major impacts on the electricity industry in Alberta. It will increase load growth directly, especially in the northeast region of the province. Economic growth associated with oilsands development will increase load growth across the province. With oilsands growth, cogeneration development will also occur. To meet growing demand and coal-fired generation retirements, and with anticipated low natural gas prices, gas-fired generation is expected to be the predominant source of new generation over the next 20 years. As part of its forecast process, the AESO consults with government agencies, distribution facility owners (DFOs), policy makers, industry experts and both load and generation entities in order to validate forecast results, incorporate the latest and expected industry trends, and align with industry development plans. Other key considerations such as overall economic growth trends (Canada and Alberta), policy evolution (federal and provincial), technology development, energy efficiency, publicly announced projects, generation economics, and the impact of Alberta s market signals are also considered in creating the 2014 LTO. PAGE 2 1.0 Executive Summary

1.1 AESO Scenarios Recognizing inputs into the forecast may change, the AESO s 2014 LTO incorporates the use of three comprehensive scenarios, established by identifying key drivers and assumptions deemed to be of high impact or importance to the forecast. These scenarios are: 1) Low Growth What if provincial growth is strongly reduced? 2) Environmental Shift What if a strong environmental policy that supports oilsands development is implemented? 3) Energy Transformation What if a strong environmental policy that severely limits Alberta s oilsands and electricity industries is implemented? These scenarios allow the AESO to analyze the impacts of changes to major forecast drivers and assumptions and test the effects on its plans and other processes. 1.2 Forecast Results The 2014 Long-term Outlook forecasts the Alberta economy to continue to grow strongly throughout the forecast period, driven by growth in oilsands development. The 2014 LTO projects electricity consumption to grow in tandem with the economic outlook, also led by growth in the oilsands energy sector. Over the next 20 years, Alberta Internal Load (AIL) is expected to grow at an average annual rate of 2.5 per cent. Natural gas-fired generation additions are expected to make up the bulk of the new capacity in response to this growing demand for energy as well as generation retirements. The 2014 LTO s three comprehensive scenarios test the major drivers and assumptions underpinning this outlook. 1.0 Executive Summary PAGE 3

2.0 Introduction The 2014 Long-term Outlook (2014 LTO) is the AESO s long-term forecast of Alberta s expected future demand and energy requirements over the next 20 years, along with anticipated generation capacity to meet those requirements. The 2014 Long-term Outlook is the starting point for the AESO s transmission planning process cycle which includes the creation of the Long-term Transmission Plan (LTP) and Regional Plans. Transmission connection studies also rely upon the 2014 LTO s load and generation forecasts. The 2014 LTO will be used by the AESO as the foundation for the next Long-term Transmission Plan. The LTP is a blueprint for ensuring the Alberta Interconnected Electric System (AIES) continues to meet the province s future electricity needs and supports the fair, efficient and openly competitive operation of the electricity market. As part of its forecast process, the AESO compared the 2014 LTO to past forecasts including the 2012 Long-term Outlook (2012 LTO) and 2012 Long-Term Outlook Update (2012 LTOU). Differences in forecast demand and generation were analyzed to determine if there were material impacts that could affect previously planned transmission facilities. Overall, the 2014 LTO is very similar to the 2012 LTOU. In most instances, changes in the 2014 LTO from the 2012 LTO and 2012 LTOU were already studied as sensitivities in transmission plans because potential major impacts were the result of load and generation project changes. Stock Photograph. PAGE 4 2.0 Introduction

The Transmission Regulation (AR 86/2007) provides additional forecast direction, requiring that the AESO, in planning the transmission system: must anticipate future demand for electricity, generation capacity and appropriate reserves required to meet the forecast load so that transmission facilities can be planned to be available in a timely manner to accommodate the forecast load and new generation capacity; must make assumptions about future load growth, the timing and location of future generation additions, including areas of renewable or low emission generation, and other related assumptions to support transmission system planning. In addition, the Long-term Plan must include for at least the next 20 years, the following projections: the forecast load on the interconnected electric system, including exports of electricity; the anticipated generation capacity including appropriate reserves and imports of electricity required to meet the forecast load; the timing and location of future generation additions, including areas of renewable or low emission generation. 2.1 Overview of the Forecast Process The AESO s outlook relies on trusted third party information, data, and processes, and reflects the latest industry outlooks. The AESO typically updates its long-term forecast every year. Alberta is growing rapidly and the change that comes with that growth requires continuous monitoring of constantly changing factors that affect both load and generation, including: Alberta s economy including key drivers such as crude oil, natural gas, and oilsands industries as well as financial and commodity market conditions Provincial, federal, and international policies and regulations concerning economic development, the environment, and the electricity industry in Alberta Technological changes including generation technologies, costs, and resource availability; energy efficiency and other Demand-Side Management (DSM) initiatives; energy storage; electric vehicles; and smart grids Announced, applied-for, approved, under-construction, and existing oilsands, industrial, generation and other projects Regional factors including specific and potential sources of load and generation changes 2.0 Introduction PAGE 5

The AESO s 2014 Long-term Outlook is effectively a study in the above factors combining the current and expected trends into a comprehensive outlook (main outlook) over the next 20 years for Alberta s economy, load, and generation. Recognizing uncertainty inherent in predicting the future, the 2014 LTO also contains three comprehensive scenarios which test key assumptions and drivers in the main outlook. The forecast process begins with the economic outlook which is derived from The Conference Board of Canada s annual long-term provincial economic forecast. 1 This economic outlook is verified against other third-party forecasts for reasonability and accuracy. The economic outlook is a 20-year view of the economy, and is therefore designed to capture long-term trends such as demographic and economic shifts rather than short-term events. The economic outlook is used as a key input to forecast electricity consumption, or energy, using the economic drivers specific to five customer sectors: Industrial (without Oilsands) Oilsands Residential Commercial Farm The Oilsands sector is separated from the Industrial sector due to its importance to the economy and its unique electricity needs. The energy forecast is then combined with point of delivery (POD) load shapes to produce an hourly load forecast by POD. The POD-level data is informed by historical data, publicly available information such as the AESO Connection Queue and Project List, 2 as well as external discussions with individual stakeholders, market participants, third-party experts, Distribution Facility Owners (DFOs), consultants, and others. In the longer term, there is naturally more uncertainty and less available information in terms of the location of future electricity needs, so the forecast relies more heavily on the trending of the long-term economic outlook. 1 www.conferenceboard.ca > Products and Services > Reports and Recordings > Economic Trends 2 www.aeso.ca > Customer Connections > Connection Queue PAGE 6 2.0 Introduction

Generation development in Alberta is a competitive business driven by independent investment decisions. In the development of the generation forecast, the forecast load is compared against currently installed generation and expected future retirements to assess the amount of incremental generation needed to reliably serve the growing demand. Generation technology drivers and costs are assessed to determine what and where resources are expected to be developed to supply future electricity load. In a process similar to that of the load forecast, the generation forecast is informed in the near term by the AESO Connection Queue and Project List, as well as by discussions with stakeholders, market participants, third-party experts, consultants, and other sources. In the longer term, the forecast relies more heavily on expected long-term trends in generation development such as relative technology costs and expected technology developments. A visual map of the forecasting process is available in Appendix B. There are key risks and uncertainties inherent in any long-term forecast, and these uncertainties increase the farther out the forecast extends in time. The 2014 LTO addresses these key risks and uncertainties using scenarios which are explained in detail in Section 7. Stock Photograph. 2.0 Introduction PAGE 7

3.0 Economic Outlook 3.1 Introduction The economic outlook is the foundation of the 2014 LTO and is a key input to the long-term load and generation forecasts. The way in which Alberta s economy changes over the next 20 years will, along with policy drivers, determine how demand and supply of electricity will develop. In the near term, the outlook is driven by current economic trends, policies and expectations for sustaining growth in exports, private investment and consumer spending. In the longer term, the outlook is driven more strongly by demographic projections and assumptions regarding labour productivity, as well as growth in oil production. The economic outlook is underpinned by The Conference Board of Canada s annual longterm provincial economic forecast. This forecast is validated for reasonability against other third-party economic forecasts. 3.2 Economic Outlook Global economic growth to drive demand for Alberta s resources Reduced fiscal constraint and the supply-chain effect that the more successful European countries are having on the other European Union (EU) member countries is expected to result in economic growth following two years of recession in the EU. While Europe accounts for less than 10 per cent of Canadian exports, positive growth in the region could certainly help bolster demand for Canadian goods directly, and also indirectly by building on global demand. While the performance of developed and developing economies has been mixed recently, the contribution of China and other developing economies to global growth continues to rise. Moreover, China s reliance on exports is easing, with domestic demand and household consumption there rapidly emerging as a source of growth for its domestic economy and as a growing opportunity for global exporters, including Canada. Over the past decade, raw material prices skyrocketed by nearly 80 per cent, providing a huge influx of revenue into the Canadian economy and boosting profits, investment, and income. While raw material prices are expected to stabilize over the near term and rise modestly over the longer term, this will continue to stimulate exploration and mine development throughout Canada, and it provides a solid outlook for Alberta s energy production over the medium and long terms. PAGE 8 3.0 Economic Outlook

Solid U.S. growth and retreat of Canadian dollar boost Canadian economic growth In 2013 the U.S. economic growth was slowed by untimely fiscal action, as a combination of tax increases and spending cuts at the beginning of the year chopped around 1.5 percentage points from real GDP growth. In 2014, less restrictive fiscal policy suggests that government will be much less of a drag, removing 0.4 percentage points from economic growth. Low relative labour and energy costs, along with solid corporate profits, have bolstered growth in private investment on structures and machinery. These trends are expected to continue, lifting near-term hiring and output growth. The medium-term outlook is relatively solid as the U.S. economy is anticipated to slowly catch up to its potential. And, while further setbacks are possible, a strengthening U.S. economy should go a long way in shoring up investor confidence on a global level. Canadian economic growth driven by demand for resources Over the past few years, a two-tiered Canadian economy has emerged, with resource-rich Saskatchewan, Alberta and Newfoundland and Labrador outperforming the rest of the country. However, the outlook for most of the provinces is positive as they benefit from a stronger U.S. economy, improving business and consumer confidence, and a firmer domestic economy. While the fiscal situation remains tenuous in several provinces, beyond 2017 economic growth is expected to slow as it realigns with weakening growth in potential output. Slower population growth and the effects of an aging population will restrain labour force growth and heavily influence income and spending patterns. Despite the negative effects of these demographic trends on the economy, real GDP growth will average Stock Photograph. 3.0 Economic Outlook PAGE 9

2.1 per cent annually over the 2018 to 2035 periods, thanks to heavy investment in machinery, equipment and technology, and in firms utilizing more highly skilled workers and more innovative production processes. Over the 2026 2035 period, strong labour productivity getting more output per hour worked is a key assumption underlying the projections, with real GDP growth forecast to ease to 1.8 per cent over the later years of the forecast. Oilsands development continues to drive Alberta s strong economic growth The Alberta economy will advance solidly over the next 20 years, expanding at a compound average annual rate of 2.4 per cent with the province s energy sector, especially oilsands, being the driving force. While Canadian oil prices have been lower than other global crude oil prices, the oilsands are, and are expected to remain, profitable throughout the forecast. Strong oilsands development driving the Alberta economy is further evidenced by the Alberta Inventory of Major Projects (Figure 3.2-1) which shows how capital investment in the oilsands sector dwarfs all other sectors. That investment will spur construction especially in the near term, create jobs, and support all other areas of the Alberta economy. Significant oilsands growth driving the Alberta economy is a major assumption of the 2014 LTO. Recognizing there are potential risks to assuming strong oilsands growth, the AESO created scenarios including a Low Growth Scenario (Section 7). While the long-term forecast for the province is favourable, the aging of Canada s population will take its toll on economic output across the country, including in Alberta. Weaker demographic conditions will slow the Alberta economy in the mid-to-long term. Figure 3.2 1: Inventory of Major Projects in Alberta Figure 1: Inventory of Major Projects in Alberta Oilsands Pipelines Oil and Gas Infrastructure Power Commercial / Retail Institutional Tourism / Recreation Residential Chemicals and Petrochemicals Agriculture and Related Mining Biofuels Other Industrial Forestry and Related Manufacturing $0 $20,000 $40,000 $60,000 $80,000 ($Cdn Millions) $100,000 $120,000 Source: Alberta Enterprise and Advanced Education (Feb. 2014) PAGE 10 3.0 Economic Outlook

3.3 Energy Commodity Outlook Abundant tight gas supply expected to keep prices weak Due to the abundance of unconventional natural gas resources including shale and other tight sources, the North American gas industry has expanded considerably over the past five years, and the 2014 LTO forecasts continued expansion. The abundance of supply is expected to keep a ceiling on natural gas prices which rise gradually through the latter half of the forecast. Relatively low prices have already impacted generation development plans in Alberta with a significant number of announced gas-fired generation projects over the near and mid term. Natural gas as a fuel source is also attractive because it is the least carbon-intensive among fossil fuel sources. Continued global oil demand will sustain oil prices Overall, the global economy is expected to grow over the next 20 years of the 2014 LTO. This growth will result in increasing energy demand, driven mainly by increasing consumption from countries outside the Organization for Economic Co-operation and Development (OECD). While demand for all forms of energy is expected to increase, crude oil will remain the dominant fuel source as demand for it rises. As demand rises and supplies of lower cost crude oil sources become depleted, crude oil prices rise throughout the forecast. Oilsands production to double over the next decade Continued global interest in Alberta s oilsands resources is expected due to the massive size of the reserves, favourable and stable political and fiscal terms, and demand from countries and companies looking for new and additional sources of crude oil supply. Oilsands bitumen production is expected to increase from approximately 2 million barrels per day (bbl/d) today to 3.9 million bbl/d by 2024 and to 4.9 million bbl/d by 2034. While there are risks to the future development of Alberta s oilsands, generally the conditions are favorable for strong growth. The AESO s 2014 LTO assumes that oil export constraints will be addressed and policies will continue to support development. 3.0 Economic Outlook PAGE 11

4.0 Environmental Drivers 4.1 Introduction The electricity industry is affected by a wide range of environmental regulations, both federal and provincial. The main environmental drivers that most affect the 2014 LTO are summarized in this section. These drivers are key because they directly impact the outlook for generation development in Alberta. However, there are several other environmental regulations, either under development, or in existence but expected to have a lessor impact on various parts of the forecast, which are detailed in the Environmental Considerations Section of Appendix C. The 2014 LTO assumes that regulations currently in force at time of writing will persist through the forecast, with existing policy lending overall direction to the forecast. Policy and regulation are significant sources of uncertainty in the 2014 LTO. Policy change risk to the 2014 LTO is explored through the development of comprehensive scenarios, which are described in Section 7. 4.2 Coal-fired Generation of Electricity Regulations In September 2012 the Canadian federal government enacted the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, 3 which will reduce carbon dioxide (CO2) emissions from the country s coal-fired generation fleet. Photo courtesy of TansAlta 3 http://www.gazette.gc.ca/rp-pr/p2/2012/2012-09-12/html/sor-dors167-eng.html PAGE 12 4.0 Environmental Drivers

The regulation allows existing coal units up to 50 years of operational life before they must either retire or retrofit with carbon capture and storage (CCS). The first significant retirements are expected to occur in 2019. Given the current costs of CCS, the 2014 LTO anticipates that no new coal-fired plants will develop. The high cost of CCS also drives the replacement of retiring coal-fired generation with less costly technologies like combinedcycle natural gas-fired generation. 4.3 Specified Gas Emitters Regulation While federal regulations set minimum emission standards for coal-fired generation, Alberta also has a provincial greenhouse gas (GHG) policy. Alberta s current GHG regulation, the Alberta Specified Gas Emitters Regulation (SGER), 4 was enacted in 2007. The regulation requires industrial facilities, including electricity generators which emit more than 100,000 tonnes of GHG per year, to reduce their corresponding emissions intensity by 2 per cent per year up to a limit of 12 per cent. The use of credits and financial contributions 5 to the Climate Change and Emission Management Fund (CCEMF), 6 which invests in projects related to Alberta s climate change strategy, is also allowed as a compliance mechanism. Since implementation of the regulation in July 2007 to the end of March 2013, the Alberta Emissions Offset Registry (AEOR) has registered a total of 137 projects and serialized almost 28 million tonnes (Mt) of GHG emission reductions or removals through registration of offset projects. 7 This regulation impacts the levelized cost of electricity of generation technologies. For those units that emit more than 100,000 tonnes of GHG per year, there is additional cost from the requirement to offset GHG emissions with credits or financial contributions. For renewable technologies, such as wind, credits are received for emissions that they offset, decreasing the levelized costs. SGER is currently under review by the provincial government as the regulation expires September 2014. The regulation is expected to be renewed but any changes to it and alignment with federal policy initiatives are not available at time of writing. 4 http://environment.alberta.ca/01838.html 5 Currently $15/tonne for every tonne exceeding the allocated limit 6 http://ccemc.ca/ 7 http://carbonoffsetsolutions.climatechangecentral.com/policy-amp-regulation/alberta-offset-system-compliance-aglance/2012-compliance-year 4.0 Environmental Drivers PAGE 13

5.0 Provincial Outlook 5.1 Introduction Oilsands growth to drive strong load growth, especially in the Northeast Region, while gas-fired generation becomes dominant baseload technology As mentioned in the economic outlook in Section 3, it is expected that the energy sector, especially oilsands, will be the driving force of Alberta s economy. Strong growth in the oilsands means significant development of load in the northeast of the province is expected. Oilsands growth also has secondary and tertiary effects on other parts of the province. Pipelines to move bitumen, diluents, and other products are required both to export bitumen from Alberta and also to move products within Alberta. Other industries such as chemicals, metals, and machinery manufacturing also directly benefit from expanding oilsands. As the oilsands expand, it is also expected that there will be significant job creation which will encourage immigration to Alberta. As Alberta s population increases, so too will demand for goods and services from a wide array of businesses. With population growth and increased business activity, residential and commercial demand will grow, especially in urban centres. Stock Photograph. PAGE 14 5.0 Provincial Outlook

As energy and load growth occurs and existing generation retires, new generation development is expected. The types and location of future generation development depend upon available technologies and fuel sources, comparative generation technology costs, and policy. Based on expected trends, gas-fired generation will be a significant technology source in providing baseload and peaking generation capacity through the addition of cogeneration, combined-cycle, and simple-cycle. This gas-fired generation will be complemented by additional renewable development. The AESO uses a comprehensive methodology to forecast future energy, load, and generation which includes third-party assessments, discussions with industry and stakeholders, and reviews of the latest and expected economic, policy, technological, and demographic trends. Regional forecasts are discussed in greater detail in Section 6, while details of the AESO s overall forecast methodology and assumptions can be found in Appendices B and C. Additional detailed forecast results can be found in the 2014 LTO data file. 5.2 Energy & Load As mentioned, oilsands development is expected to be a major driver of overall electricity consumption within Alberta. There are a significant number of oilsands projects currently under various forms of development that are expected to be completed over the next five years. These projects, along with the economic spinoff and job creation resulting from their development, are expected to drive strong average annual Alberta Internal Load (AIL) energy consumption growth in the near term. As part of its forecast process, the AESO individually analyzes and forecasts electricity consumption by five customer sector types according to each type s unique characteristics and drivers. The Oilsands sector forecast is mainly project-driven and is expected to grow the fastest at an average annual rate of 4.5 per cent over the next 20 years. The Industrial (without Oilsands) sector is forecast to grow at 2 per cent over the next 20 years, driven mainly by growth in industries associated with oilsands and economic growth including pipelines, petrochemical, and manufacturing. Residential electricity consumption is driven by population growth as well as changes in consumption behavior. Over the forecast, residential electricity use is expected to grow at an average annual rate of 1.6 per cent. Commercial electricity consumption is forecast to grow at an average annual rate of 2.2 per cent as that sector grows with the overall economy. Over the next 10 years, AIL energy growth is forecast to remain robust as additional oilsands projects develop and contribute to economic growth. Over the next 20 years, energy growth is not expected to remain as strong as in the nearer term. Greater uncertainty about future oilsands and other development in the province, reduced oilsands and economic growth along with improvements in energy efficiency result in a lower rate of AIL energy consumption growth. Over the next 20 years, AIL energy is forecast to grow at an average annual rate of 2.5 per cent. The AESO s energy forecast can be found in Appendix A and additional details and assumptions regarding the energy forecast can be found in Appendix C. Similar to AIL energy, AIL peak is forecast to grow at an average annual rate of 2.5 per cent over the next 20 years. System load, which excludes load served by onsite generation, is expected to grow slightly slower than AIL at a rate of 2.3 per cent over the next 20 years. 5.0 Provincial Outlook PAGE 15

5.3 Generation In developing the generation forecast, assessments of each technology are performed including location and fuel availability, current developments, relative levelized costs, and impact of policy. Generation development over the next 20 years is expected to be strong as a result of growth in AIL and the retirement of large coal-fired facilities. The economics around generation has combined-cycle as the lowest cost technology while wind energy has the second lowest cost. Other technologies such as cogeneration will see development as the benefits of captured heat within industrial applications is strong. In the first 10 years, generation development in the oilsands is primarily expected to be cogeneration and baseload combined-cycle in anticipation of both coal-fired retirements and increased AIL. In addition to the baseload generation, some developments of wind facilities and gas-fired simple-cycle have been forecast. Wind development is economically challenging; however, many wind projects remain interested in connection to the transmission system. In the latter half of the forecast, large additions of baseload generation are expected to develop in response to further retirement of coal-fired units and continued load growth. Combined-cycle is the main type of baseload technology developing in the forecast. Cogeneration development in the second 10 years of the forecast is lower than the first 10 years, reflecting slower overall oilsands growth. Wind sees little growth as forecast economics remain challenging and existing policy is not strong enough to provide adequate incentives. Additions of other generation technologies also continue in the second 10 years but at a reduced level. 2014 LTO: Generation Capacity Mix Comparison Existing as of December 31, 2013 Total Capacity: 14,568 AIL Peak: 11,139 2019 Total Capacity: 18,259 AIL Peak: 14,274 2024 Total Capacity: 21,039 AIL Peak: 16,014 2034 Total Capacity: 24,953 AIL Peak: 18,519 43% Coal 6,271 29% Cogeneration 4,245 6% Combined-cycle 843 6% Simple-cycle 804 6% Hydro 894 7% Wind 1,088 3% Other 423 30% Coal 5,402 33% Cogeneration 6,003 14% Combined-cycle 2,513 7% Simple-cycle 1,228 5% Hydro 894 10% Wind 1,751 3% Other 468 26% Coal 5,402 30% Cogeneration 6,302 19% Combined-cycle 4,001 8% Simple-cycle 1,679 4% Hydro 894 11% Wind 2,263 2% Other 498 10% Coal 2,509 27% Cogeneration 6,737 36% Combined-cycle 8,871 10% Simple-cycle 2,399 4% Hydro 894 11% Wind 2,679 3% Other 864 Total 14,568 MW Total 18,259 MW Total 21,039 MW Total 24,953 MW Source: AESO PAGE 16 5.0 Provincial Outlook

6.0 Regional Outlooks 6.1 Introduction As the 2014 LTO will be used as a basis for AESO planning, it has a regional focus that examines key features of the AESO s planning regions along with an assessment of the key drivers and trends that affect both load and generation within each region. This regional approach helps the AESO to understand the geographical impacts associated with forecast load and generation. Figure 6.1 1: AESO Planning Regions and Areas 17 Rainbow Lake 18 High Level 25 Fort McMurray 19 Peace River * Planned areas are numbered Source: AESO 20 Grande Prairie 22 Grande Cache 23 Valley View 24 Fox Creek 29 Hinton / Edson AESO Planning Regions* Central Edmonton Northeast Northwest South 21 High Prairie 26 Swan Hills 34 Abraham Lake 40 Wabamun 30 Drayton Valley 38 Caroline 44 Seebee 31 Wetaskiwin 35 Red Deer 39 Didsbury 57 Airdrie 6 Calgary 45 Strathmore/ Blackie 46 High River 27 Athabasca / Lac La Biche 60 Edmonton 33 Fort Sask. 56 49 Stavely Vegreville 36 Alliance/ Battle River 53 Fort MacLeod 54 Lethbridge 55 Greenwood 32 Wainwright 42 Hanna 43 Sheerness 47 Brooks 28 Cold Lake 13 Lloydminster 37 Provost 48 Empress 52 Vauxhall 4 Medicine Hat 6.0 Regional Outlooks PAGE 17

6.2 Northeast Region Northeast growth contingent upon ongoing oilsands development The Northeast Planning Region is characterized by a relatively sparse population but significant amounts of industrial load and cogeneration. It is also the fastest growing region in terms of load as new oilsands and other industrial projects connect to the AIES and ramp up. Table 6.2 1: Northeast Characteristics 2013 Average Load (MW) 2,460 2013 Summer Peak (MW) 2,231 2013/2014 Winter Peak (MW) 2,877 Population (000s) 245 Area (000 km2) 184 Source: Alberta Municipal Affairs, AESO 6.2.1 Load The majority of load in the Northeast Region is industrial-based. The Fort McMurray (Area 25) and Cold Lake (Area 28) areas contain the majority of the province s oilsands operations. The Fort Saskatchewan area (Area 33) contains the Industrial Heartland which includes some oilsands activity such as the Shell Scotford Upgrader, as well as a significant number of other industrial facilities. The Athabasca/Lac La Biche area (Area 27) has a relatively low load compared to other planning areas in the Northeast Region; however, it does contain a number of forestry facilities. Overall, the population in the Northeast is relatively low at approximately 245,000 or about 7 per cent of the province s total population. Most of these residents live in the Regional Municipality of Wood Buffalo which has a population of approximately 116,000 including a shadow population of about 42,000 temporary workers. 8 The low population in the region means there is minimal residential and commercial load. Despite the low population, the Northeast Region contains approximately 29 per cent of AIL. The high amount of industrial load and relatively low amount of residential and commercial load in the Northeast means that the region has a comparatively flat load profile. However, there is some seasonal variation with higher load levels in winter. The Northeast Region contains the majority of oilsands load. The 2014 LTO oilsands forecast is based on a bottom-up approach which adds up all oilsands projects and adjusts them based on development status so that the oilsands forecast aligns with industry projections of oilsands growth. Over the past 10 years, the Northeast Region experienced stronger load growth than any other region, growing at an average annual rate of 5.1 per cent. As oilsands projects develop and the industry expands, it is expected that the Northeast Region s load will grow rapidly and be the fastest growing of any region with average annual growth of 3.4 per cent over the next 20 years. 8 Source: Alberta Municipal Affairs http://www.municipalaffairs.gov.ab.ca/mc_official_populations.cfm PAGE 18 6.0 Regional Outlooks

6.2.2 Generation The Northeast Region contains a variety of sources of energy that can be used to create electricity. The region currently contains: Natural gas-fired generation from industrial sites in the Fort Saskatchewan, Fort McMurray and Cold Lake areas Biomass generation in the Athabasca area Over the last 10 years the Northeast Region has seen almost 1,300 MW of net generation additions, primarily from cogeneration. The region has also seen the addition of a small amount of biomass. Potential generation development in the Northeast Region consists of gas-fired and hydroelectric (hydro) generation. Gas-fired generation could come from cogeneration related to the oilsands, baseload combined-cycle, and/or simple-cycle peaking. With growth in the oilsands, cogeneration is an attractive source of generation where both power and heat can be produced. The region also has potential from large combined-cycle units with capacities in the 500 to 1,000 MW range. Currently, there are 940 MW of combined-cycle and 180 MW of simple-cycle projects that have applied for AESO connection in the Fort Saskatchewan area. Hydroelectric generation is also a potential source of energy in the region. Projects have been discussed for the Slave River area with capacities of approximately 1,000 MW. In the next 10 years, additions of cogeneration related to oilsands development and combined-cycle generation to meet expected baseload requirements are forecast for the region. In addition to combined-cycle, the forecast has an increase in peaking capacity in the region. The forecast in the second 10 years has smaller growth of cogeneration related to reduced growth in oilsands development, but has continued growth in combined-cycle and simplecycle generation to meet load increases and coal-fired retirements. Table 6.2.2 1: Northeast Load and Generation Capacity Forecast MW Existing 2024 2034 Load at AIL Peak 2,877 5,265 5,855 Coal-fired 0 0 0 Cogeneration 3,372 4,739 5,174 Combined-cycle 0 940 2,210 Simple-cycle 0 180 450 Hydro 0 0 0 Wind 0 0 0 Other 149 149 149 6.0 Regional Outlooks PAGE 19

6.3 Northwest Region New oilsands developments changing the Northwest landscape The Northwest Region is characterized by low population, a relatively high proportion of industrial load, low growth in recent years and a respectable amount of oilsands potential, including cogeneration, in the Peace River area. There is currently a variety of generation in the area including biomass, coal-fired, and gas-fired units. Table 6.3 1: Northwest Characteristics 2013 Average Load (MW) 1,040 2013 Summer Peak (MW) 883 2013/2014 Winter Peak (MW) 1,111 Population (000s) 173 Area (000 km2) 230 Source: Alberta Municipal Affairs, AESO 6.3.1 Load Over the past 10 years, load growth in the Northwest has been the lowest of any of the regions with an average annual peak load growth rate of 1.2 per cent. Of the five AESO planning regions, the Northwest has the lowest population with approximately 172,000 people or less than five per cent of Alberta s population. The largest population centre in the Northwest is Grande Prairie with a population of about 55,000. The low population means residential and commercial electricity demand is relatively low and industrial demand is relatively high. The Northwest Region also contains some agricultural activity. With a low population, there is a relatively small amount of residential and commercial load compared with other regions. The relatively high amount of industrial demand means the region has the highest load factor of any region. Industrial load in the region is comprised of forestry sites and oil and gas, including unconventional plays such as the Montney play. There is also some oilsands activity (mostly small test/pilot projects) and associated pipelines, as well as some manufacturing including chemicals. The AESO expects that load growth will occur in the Northwest Region due to expansion of oilsands projects in the Peace River area along with associated infrastructure development. As a result, the Northwest Region is forecast to grow at an average annual rate of 1.8 per cent over the next 20 years. PAGE 20 6.0 Regional Outlooks

6.3.2 Generation The Northwest Region has many sources of energy that can be used to create electricity. The region currently contains: Coal-fired generation in the Grande Cache area Natural gas-fired generation Biomass generation Net generation developments in the last 10 years totalled approximately 350 MW from a variety of sources including coal-fired, gas-fired, and other technologies such as biomass. Gas-fired generation has the highest potential for future development in the Northwest Region. In addition, there is also potential from biomass, waste heat, hydro, and Integrated Gasification Combined Cycle (IGCC). Gas-fired generation could come in the form of cogeneration related to oil production, baseload combined-cycle, or from simple-cycle peaking units. The area currently has applications from all three of these gas-fired technologies. The potential for biomass and waste heat is expected to be small as many existing industrial sites have already adopted generation, but there remains potential for the growth of new developments. While there are no IGCC projects with applications at the AESO, projects have previously been announced and could return. Hydroelectric generation, such as the Dunvegan Hydroelectric Project, has also been proposed for the region and could be developed in the future. The forecast for the Northwest Region in the first 10 years includes the addition of the 690 MW Carmon Creek cogeneration project. The forecast also includes the development of simple-cycle peaking units. The first 10 years is also expected to see some growth in smaller generation technologies such as biomass. There is uncertainty around the timing of larger generation sources such as combined-cycle. No units have been included in the first 10 years, although sensitivities can be performed to test the impact of earlier development. Retirements in the region could see the H.R. Milner plant either decommission or significantly reduce annual generation to meet federal GHG requirements. Gas-fired retirements from three Rainbow and two Sturgeon units have also been included. The second 10 years forecast has continued development of gas-fired generation through the addition of baseload combined-cycle and simple-cycle peaking. Hydro has not been included in the outlook as the economics and capital risks do not appear to currently support the development. 6.0 Regional Outlooks PAGE 21

Table 6.3.2 1: Northwest Load and Generation Capacity Forecast MW Existing 2024 2034 Load at AIL Peak 1,111 1,443 1,628 Coal-fired 144 0 0 Cogeneration 191 881 881 Combined-cycle 73 73 773 Simple-cycle 364 523 703 Hydro 0 0 0 Wind 0 0 0 Other 171 212 262 6.4 Edmonton Region Edmonton Region to remain major generation centre as new combined-cycle facilities complement steady urban load growth The Edmonton Region contains the city of Edmonton and surrounding communities. It contains the second largest population of the AESO s five planning regions with about 1.2 million people or about 34 per cent of the total population. It also contains the most significant amount of generation capacity located in the Wabamun area. Table 6.4 1: Edmonton Region Characteristics 2013 Average Load (MW) 1,569 2013 Summer Peak (MW) 2,166 2013/2014 Winter Peak (MW) 2,158 Population (000s) 1,234 Area (000 km2) 22 Source: Alberta Municipal Affairs, AESO 6.4.1 Load The Edmonton Region has approximately 20 per cent of Alberta s load. Much of this is residential and commercial load associated with the City of Edmonton. However, there is also a significant amount of industrial load including demand from Refinery Row as well as other manufacturing and pipeline load. Over the past 10 years, the Edmonton Region load has grown at an average annual rate of 1.9 per cent. Future growth is expected to be in line with forecast average annual growth of 2.1 per cent over the next 20 years, driven primarily by residential, commercial and industrial development associated with the province s expected overall economic and population growth. The bulk of this forecast growth is anticipated to occur in the Edmonton area (Area 60). PAGE 22 6.0 Regional Outlooks

6.4.2 Generation The Edmonton Region contains primarily coal-fired generation with the potential for gasfired generation. The region currently contains: Coal-fired generation in the Wabamun area Natural gas-fired generation within the Edmonton area The Edmonton Region has seen a net increase in supply of 121 MW in the last 10 years. There have been large retirements from the old Clover Bar units as well as coal-fired retirements from the Wabamun units. This has been offset with both coal-fired and gas-fired additions. The most likely future generation fuel source in the Edmonton Region is natural gas. The region has existing infrastructure that can be used to connect large-scale generation, making it an attractive location for future development. In addition, as existing coal-fired units in the region retire, the infrastructure could accommodate new baseload generation. There is currently over 2,700 MW of interest in gas-fired generation for the region. Smaller district energy and microgeneration have the potential for development within large urban areas, such as the 39 MW unit at the University of Alberta. Waste heat applications have also been announced and have the potential for development. The forecast for the Edmonton Region in the next 10 years is for the addition of one combined-cycle unit and the retirement of approximately 600 MW of coal-fired generation. Given the need for baseload generation in the first 10 years and the attractiveness of the region, combined-cycle generation could develop within the region. In the mid-to-long term, there is continued development of large combined-cycle generation and retirements of coal-fired generation forecast for the region. Additional smaller technologies such as waste heat capture are also expected to develop. Table 6.4.2 1: Edmonton Region Load and Generation Forecast MW Existing 2024 2034 Load at AIL Peak 2,158 2,785 3,340 Coal-fired 4,658 4,082 1,729 Cogeneration 39 39 39 Combined-cycle 0 900 3,300 Simple-cycle 250 250 250 Hydro 0 0 0 Wind 0 0 0 Other 0 0 158 6.0 Regional Outlooks PAGE 23

6.5 Central Region New pipelines in Central East drive new load growth while generation has modest growth The Central Region contains a relatively low population which is mainly concentrated in the Red Deer area (Area 35). The Red Deer area contains significant amounts of chemical and other manufacturing. In addition, there are significant pipeline concentrations, especially on the eastern portion of the region. Recent years have seen the addition of two new wind facilities. Table 6.5 1: Central Region Characteristics 2013 Average Load (MW) 1,282 2013 Summer Peak (MW) 1,338 2013/2014 Winter Peak (MW) 1,608 Population (000s) 361 Area (000 km2) 131 Source: Alberta Municipal Affairs, AESO 6.5.1 Load The Central Region contains about 352,000 people or about 10 per cent of Alberta s population but about 15 per cent of AIL. The Red Deer area contains significant industrial load related to chemical and other manufacturing. In addition, there is significant pipeline load, especially on the eastern portion of the region. An important feature of the Central Region to the load forecast is the significant number of pipeline-related projects and development. Hardisty is a major crude oil pipeline terminal storage centre located in the Lloydminster planning area. Several intra-alberta pipelines are connected to it with additional projects planned. Also, two major export pipelines, Keystone XL and Energy East, are planning to connect to Hardisty and they will run along the east side of the Central Region before turning east into Saskatchewan. The pumping stations used to move crude oil through these various pipelines is expected to be a significant source of load growth in the Central East Region. Over the next 20 years, the AESO forecasts the Central Region s load to grow at an average annual rate of 2.1 per cent due to increasing pipeline loads as well as urban load in the Red Deer area and other industrial growth. 6.5.2 Generation The Central Region has many sources of energy that can be used to create electricity. The region currently contains: Coal-fired generation in the Battle River area Natural gas-fired generation Hydroelectric generation including the large Bighorn and Brazeau facilities Wind facilities Biomass generation PAGE 24 6.0 Regional Outlooks

In the last 10 years there has been approximately 300 MW of new generation additions, with 232 MW from new wind facilities and the remainder from gas-fired units. The region has generation potential from natural gas, wind, and small scale technologies such as biomass and waste heat. Natural gas-fired generation in the Central Region currently consists of the large 474 MW Joffre cogeneration facility and small 15 MW units related to gas development. In addition to gas-fired generation for industrial reasons, the region could see the development of simple-cycle peaking units or larger combined-cycle units that utilize existing infrastructure. The AESO connection queue illustrates interest in gas-fired generation in this region. The potential for wind is strong in this region, and numerous projects have applied to the AESO for connection to the transmission system. Two wind facilities have developed in the Central Region, increasing the geographic diversity of wind in the province. While not expected to be a major contributor to generation capacity, there is potential for biomass and the ability to capture waste heat from pipeline compressors or other industrial processes. The forecast for the Central Region in the first 10 years has the largest growth in gas-fired and wind generation. Gas-fired additions are related to small industrial installments as well as peaking generation. Wind resources in the region are attractive and there has been considerable interest in development in the region. A change in policy that improves the economics of renewables could increase the amount of wind that develops. The forecast has a moderate increase in wind generation in the region. In addition to gas-fired and wind generation, the forecast has small additions from other technologies. Possible retirements in the first 10 years include the Battle River 3 and 4 coal-fired generators. The forecast assumes the retirement of only Battle River 3 in the first 10 years with scenarios looking at alternative retirement schedules. In the mid-to-long term, gas-fired and wind generation are the primary technologies forecast to be developed. The second 10 years assumes the development of a large combinedcycle unit in response to a need for baseload generation. Based on federal regulations, the forecast has the retirement of the Battle River 3, 4, and 5 units within the 20-year time frame. Table 6.5.2 1: Central Region Load and Generation Forecast MW Existing 2024 2034 Load at AIL Peak 1,608 2,152 2,466 Coal-fired 689 540 0 Cogeneration 536 536 536 Combined-cycle 0 0 500 Simple-cycle 5 180 270 Hydro 485 485 485 Wind 232 439 505 Other 61 76 84 6.0 Regional Outlooks PAGE 25

6.6 South Region Calgary to drive South load growth with large potential for wind development The South Region is the second smallest region in terms of land size but the most populous of all the regions because of the cities of Calgary, Lethbridge and Medicine Hat. The South Region is also characterized by the most wind generation of any region. Table 6.6 1: South Region Characteristics 2013 Average Load (MW) 2,224 2013 Summer Peak (MW) 3,059 2013/2014 Winter Peak (MW) 3,041 Population (000s) 1,691 Area (000 km2) 95 Source: Alberta Municipal Affairs, AESO 6.6.1 Load The South Region has approximately 1,651,000 people or about 45 per cent of Alberta s population. Most of this population is concentrated in and around Calgary (Area 6) which is a concentration point of residential and commercial demand. The South Region also contains industrial loads as well as the majority of farm demand. A unique feature of the South Region is that it is the only region with higher summer peaks than winter peaks for the past three years (2011-2013) due to higher air conditioning use and seasonal irrigation loads. Overall, the South Region represents approximately 26 per cent of AIL. The South Region s load is expected to grow moderately at 2.1 per cent over the next 20 years, driven principally by residential and commercial development associated with the province s overall economic and population growth. The bulk of this growth is expected to occur in and around the city of Calgary. 6.6.2 Generation The South Region contains a variety of sources of energy that can be used to create electricity. The region currently contains: Coal-fired generation in the Sheerness area Natural gas-fired generation with large assets located around Calgary and Medicine Hat Hydroelectric generation on the Bow River and the Oldman River and its tributaries Large amounts of wind between the Fort MacLeod area and Medicine Hat The South has seen a large amount of variable generation come online in the last 10 years with a total of 703 MW of new wind. Overall the region has had a total of 960 MW of net additions to the region. PAGE 26 6.0 Regional Outlooks

The largest potential for future generation in the 20-year timeframe is from natural gas, wind and solar. Currently, the 800 MW Shepard Energy Centre is under construction and expected to begin commercial operation in 2015. In addition, other gas-fired generation has applied to the AESO for connection. Wind potential within the region is strong, with approximately 2,500 MW of wind projects in the AESO queue. Policies for renewable energy sources could drive strong growth in wind facilities. Southern Alberta also has the most favourable solar resources in the province, although there are currently no transmissionconnected solar facilities. Medicine Hat is developing a 1 MW solar project with funding from the CCEMF. Through the Alberta Micro-generation Regulation, residential and commercial solar is continuing to develop. The forecast for the South includes primarily gas-fired and wind facilities. In addition to the Shepard Energy Centre, smaller gas-fired generation has been announced and development of this generation could be expected near the end of the first 10 years. There is currently 350 MW of wind facilities under construction in the South Region. In addition to the projects under construction, there is considerable interest in wind generation as reflected in the amount of wind projects that have applied to the AESO. The second 10 years of the forecast has less generation development than the first 10 years. Again, the primary sources of development are through gas-fired and wind facilities. The region also has the potential for development within urban areas. There is the potential for combined heat and power facilities, similar to the 15 MW unit at the University of Calgary, as well as the potential for microgeneration. Possible retirements in the region include the Sheerness 1 and 2 coal-fired generators. These units are expected to retire on or before 2036 and 2040 respectively. Table 6.6.2 1: South Region Load and Generation Forecast MW Existing 2024 2034 Load at AIL Peak 3,041 3,887 4,674 Coal-fired 780 780 780 Cogeneration 107 107 107 Combined-cycle 770 2,088 2,088 Simple-cycle 185 546 726 Hydro 409 409 409 Wind 856 1,824 2,174 Other 42 61 211 6.7 Outlook Summary and Risks The 2014 LTO captures the expected future demand and energy requirements over the next 20 years, along with anticipated generation capacity to meet those requirements. Figure 6.7-1 shows the regional outlook for load. Additional details of the outlook can also be found in Appendix A and in the 2014 LTO data file. 6.0 Regional Outlooks PAGE 27

Figure 6.7 1: Regional Load Forecast Summary 8,000 6,000 Northwest 8,000 6,000 Northeast (MW) (MW) 4,000 2,000 0 8,000 6,000 4,000 2003 2008 2013 2019 2024 2034 Edmonton NW NE (MW) (MW) 4,000 2,000 0 8,000 6,000 4,000 2003 2008 2013 2019 2024 2034 Central 2,000 0 Edm 2,000 0 2003 2008 2013 2019 2024 2034 AESO Planning Regions Central Edmonton Northeast Northwest South Central South (MW) 8,000 6,000 4,000 2,000 0 2003 2003 2008 2013 2019 2024 South 2008 2013 2019 2024 2034 2034 6.7.1 Load Risks The main risks for the load forecast concern factors that affect load growth and load potential. Since the 2014 LTO assumes strong oilsands growth will drive strong economic and load growth, the primary risk is that the strong forecast growth rates do not materialize as expected. Numerous factors could affect future oilsands development. In the near term, these include: rising costs of materials and labour, commodity prices, export constraints, environmental policy including air emissions, land use, water use tailings, taxes and royalties, and financial market conditions. In addition, technological change within the oilsands could change the outlook for electricity demand. Risk of lower oilsands growth is addressed through the Low Growth Scenario (Section 7.3) while technological change that could increase oilsands demand is addressed through the Environmental Shift Scenario (Section 7.4). Another risk is how demand-side management (DSM) changes could impact load. Improvements in residential and commercial energy efficiency could reduce load. The AESO s Environmental Shift and Energy Transformation scenarios test increases in energy efficiency in the residential and commercial sectors. Additional load risk comes from regional factors. In the Northwest Region, oilsands have started to expand and develop at a more rapid rate. The ultimate potential of this development and affiliated load is uncertain. The Northwest also contains a significant amount of forestry operations. The 2014 LTO does not assume significant changes in the size of the forestry industry; however, changes including either expansion or contraction could also affect the load forecast. The Northwest also contains large amounts of unconventional PAGE 28 6.0 Regional Outlooks

natural gas potential. While the 2014 LTO expects development of that natural gas to continue, significant changes to the natural gas industry could also affect the load forecast. The main load risk in the Edmonton, Central, and South Regions is the pace of load growth associated with overall provincial economic development and population growth. The forecast urban growth in Calgary and Edmonton as well as smaller urban centres is largely associated with immigration caused by job creation in Alberta s growing economy. These regions could be impacted if economic growth does not occur as expected. In addition, there are a number of pipelines expected to be built in the Edmonton and Central Regions that will increase load. The timing of these pipelines will affect the load forecast, especially if they are delayed or not approved. The AESO s strategy for handling pipeline risk can be found in the Energy and Load Considerations Section of Appendix C. 6.7.2 Generation Risks There are several key risks to the generation forecast. Coal retirements are guided by current regulations; however, those regulations allow certain flexibility in the timing of retirements. The location of combined-cycle is also a risk because combined-cycle projects can develop in a variety of locations as demonstrated by recently announced combined-cycle projects. Also, the amount of future development of renewable and low-emitting generation sources will be dependent on policy, which could potentially change from existing regulations. There are risks associated with the generation forecast for each region. In the Northeast and Northwest Regions the cogeneration potential is linked to the amount of total oilsands development. Significant changes to that development could affect cogeneration development. While cogeneration can generally be considered economic in some applications, companies vary in their preference for cogeneration development. Some companies prefer no cogeneration at all, while other companies prefer large-scale cogeneration development. In addition to cogeneration, there is also the possibility that other technologies like hydro could develop, given a change in policy or increased focus on water management. Risks around generation in the Edmonton Region are related to both the timing of new developments and retirement of existing coal-fired units. The timing of new developments has been adjusted in scenarios based on changes in overall load growth. As well, various retirement schedules have also been considered in the scenarios. The key risk to generation in the Central and South Regions is around the development of wind resources. The amount of wind that develops could be increased from the outlook given a change in policy related to renewable sources. Two scenarios, Environmental Shift and Energy Transformation, address increases in the amount of wind by looking at drivers that would increase wind penetration. 6.0 Regional Outlooks PAGE 29

7.0 Scenarios 7.1 Purpose Changing policies and economic drivers can significantly impact the development of load and generation in the province. This uncertainty is managed in the 2014 LTO through the creation of three integrated economic, load and generation scenarios that consider variations of key drivers. These scenarios quantify the effects of high impact, lower probability outcomes on the 2014 LTO. Scenarios are a series of alternative visions of futures which are possible, plausible, and internally consistent, but are deemed less likely. Their purpose is to confront the main outlook with possible future conditions, so that the availability and usefulness of options can be analyzed against an unknown future state. Scenarios allow the AESO to understand the potential impacts resulting from changes in key assumptions based upon assessed major risks. While scenarios are useful tools for analyzing what if type outcomes, the AESO does not specifically assume they will occur. They are meant solely as a tool for quantifying possible, but less likely, futures as opposed to the main outlook, which is primarily used for planning and other purposes. Stock photograph. PAGE 30 7.0 Scenarios

7.2 Methodology and Drivers 7.2.1 Scenarios Drivers Development of the 2014 LTO scenarios was driven by three main factors: Oilsands production and load Environmental policy Technology advances 7.2.2 Oilsands Production and Load Oilsands development and production affects load growth both directly and indirectly. First, investment in oilsands production directly increases load from the Northeast area as the amount of bitumen production increases. Second, energy investment and investment in the oilsands in particular ripples across the economy. Investment supports other industries, creates jobs that encourage immigration, and drives residential and commercial load growth. Assumptions about the growth of the oilsands sector are crucial to the forecast and there is uncertainty and risk around how much growth will ultimately occur within the industry. Numerous factors could impact the rate of development within the oilsands sector. Rising labour or materials costs, declining prices, export constraints, policy shifts, and financing/ capital availability could all negatively impact growth. There are currently numerous oilsands projects under construction or about to commence construction, and it is very likely these projects will be completed. However, further into the future, the certainty that growth will occur is reduced. 7.2.3 Environmental Policy The 2014 LTO represents current federal and provincial legislation as of the end of March 2013. The outlook assumes that current laws and regulations affecting the energy sector are largely unchanged throughout the projection period. Among all the forecast drivers, environmental policy has the greatest uncertainty in terms of both the target and the tool. The policy target could be broad across industries or specific to an industry, technology, or emission type. The policy tools could include commandand-control, taxes, and cap-and-trade. This uncertainty is even greater for deregulated electricity markets like Alberta that do not have centralized integrated resource planning like other jurisdictions. 7.2.4 Technology Advances Technological advances are often unpredictable and unforeseen. For example, few industry experts predicted how rapid and impactful hydraulic fracturing technology would be on the North American oil and gas industry. Technological advances could affect both load and generation. Load could either decrease (through energy efficiency) or increase (through electricity-based oilsands extraction). Technology advances could also affect generation by changing costs of existing technologies, introducing new sources of generation, and affecting the location and magnitude of generation development. 7.0 Scenarios PAGE 31

7.2.5 Other Drivers While the main forecast drivers are outlined above, other factors could potentially impact the main outlook. The AESO continues to monitor and analyze developments in the energy industry, both through internal and external research and through stakeholder engagement. 7.3 Low Growth Scenario What if provincial growth is strongly reduced? The Low Growth Scenario examines a world where the oilsands industry s development and overall provincial economic growth is significantly impacted. Since the primary driver of economic growth in the 2014 LTO is oilsands development, oilsands growth is reduced in this scenario to cause slower Alberta economic growth. 7.3.1 Low Growth Scenario Provincial Outlook To create the Low Growth Scenario, the AESO contracted The Conference Board of Canada to shock its economic models in a manner that slows oilsands development and growth. The forecast economic data created through this shock was then used in the AESO s forecast models. In order to test just the impact of reduced oilsands and economic growth, no additional impacts from policy or technological changes were assumed. Economic As part of the reduced growth, there is a strong impact to the oilsands industry, especially in later years, once the available export capacity is used up. In the main outlook, oilsands production reaches 3.9 million barrels per day (bbl/d) by 2024 and 4.9 million barrels per day by 2034. However, in the Low Growth Scenario oilsands production reaches just under 3 million barrels per day by 2024 and only 3.2 million bbl/d by 2034. Real GDP growth over the 20 years is reduced from 2.4 per cent in the main outlook to 1.5 per cent in the Low Growth scenario. Effectively, the province continues to grow, albeit at a much slower pace. Energy/Load To quantify the impacts of lower growth on Alberta energy and load, the impacted economic variables were used in the AESO s forecast models and the results were compared. The most significant impacts were in the Northeast Region of the province where the average annual growth rate over the next 20 years is 1.4 per cent in the Low Growth Scenario compared with 3.4 per cent in the main outlook. Generation Load from the Low Growth Scenario was incorporated into the generation forecast process. With decreased growth in demand the overall level of generation development is reduced. Cogeneration is strongly impacted as the reduction in industrial activity leads to lower heat and steam requirements. Compared to the main outlook, other generation technologies continue PAGE 32 7.0 Scenarios

to develop but at a slower pace. The comparative cost of generation technologies remains the same as the main outlook. Existing coal-fired generation remains a dominant form of power in the next five to 10 years as other technologies do not develop as quickly. Table 7.6-1 compares the Low Growth Scenario to the main outlook and other scenarios. 7.4 Environmental Shift Scenario What if a strong environmental policy that supports oilsands development is implemented? The Environmental Shift Scenario considers a world where policy makers introduce environmental regulations that improve the environmental performance of the province while still supporting oilsands development. To accomplish this, it is assumed that there is support for low-emitting technologies such as wind and cogeneration. At the same time, it is also assumed there are measures put into place requiring oilsands development to reduce land, air and water pollution while maintaining growth of the oilsands industry. 7.4.1 Environmental Shift Provincial Outlook To create the Environmental Shift Scenario, the AESO assumed there would be a fairly significant regulation shift on the part of the provincial government to improve the environmental performance of the province while still encouraging strong growth of the oilsands. Since new environmental policy would likely result in added costs to major emitting industries such as the oilsands, it is assumed that oilsands development and growth would be impacted as projects with marginal economics become unprofitable and are delayed or cancelled. To achieve this effect, a modest drop in oilsands investment was modeled and the impacts to the economy were factored into the AESO s forecast models. Major projects under construction still proceed as planned but some future projects were removed. Assumptions in addition to the economic effect, including changes to energy efficiency, were then also modeled. While this policy would increase costs to large-emitting industries, the policy would increase revenues to low-emitting generation technologies. This could be accomplished by increasing current incentives as found in the existing Specified Gas Emitters Regulation (SGER). Economic To improve the environmental performance of the oilsands, it is assumed in this scenario that the provincial government introduces measures to reduce land, air and water pollution in the oilsands. There are costs associated with this pollution reduction, causing some oilsands projects with marginal economics to become uneconomic. As a result, oilsands development and production is less in this scenario compared to the main outlook. With less oilsands development and production, there are also fewer economic spin-off effects and the overall economy grows slightly slower at 2.2 per cent compared to 2.4 per cent in the main outlook. 7.0 Scenarios PAGE 33

Energy/Load In the first 10 years of the scenario, load is lower compared to the main outlook as costs associated with environmental improvement cause oilsands growth delays. However, in the last 10 years there is a counter-intuitive effect of strongly increasing oilsands demand related to that environmental improvement. To improve upon land-use impacts, it is assumed that there are fewer oilsands facilities; however, this results in the need to transport more products greater distances by pipeline which requires additional pipeline load. It is also assumed in this scenario that water recycling increases to 100 per cent at oilsands facilities requiring additional load associated with more pumping. To reduce carbon emissions, carbon capture equipment is assumed to be used which also increases load. Finally, a significant amount of new electric-based extraction technologies are used in place of natural-gas burning Steam-Assisted Gravity Drainage (SAGD) technology to also reduce carbon emissions and this too increases oilsands load. While some efficiency gains occur, these are limited because of the already relatively high efficiency of electric motors currently used in the oilsands. These efficiency gains are overwhelmed by the adoption of new sources of load associated with improving environmental performance. Other sectors (Industrial without Oilsands, Commercial, Residential) are lower in the Environmental Shift Scenario for two reasons. With lower overall economic development resulting from slower oilsands growth, there is lower load growth. Also, as part of provincial policy to improve environmental performance, energy efficiency measures such as new building codes further reduce electric demand. Changes in the various sectors due to the policy and technological assumptions in the Environmental Shift Scenario result in an interesting change from the main outlook, especially in later years. Across most of the province, load is generally lower; however, load increases in the Northeast Region of the province. Generation In this scenario, low-emitting generation technologies are given incentives through a stronger regulation similar to the SGER. This has the overall impact of increasing development of low-emitting generation. Specifically, the relative cost of cogeneration, wind and hydro are all improved, leading to increased development of these technologies. In the near term, cogeneration and wind have higher development than the main outlook, even given a reduction in overall load. Combined-cycle in the same timeframe continues to be a required baseload technology that develops, and there is also an increase in simple-cycle generation. With an assumed development period for hydro of eight to twelve years, largescale hydro doesn t develop until into the second 10 years. Table 7.6-1 compares the Environmental Shift Scenario to the main outlook and other scenarios. PAGE 34 7.0 Scenarios

7.5 Energy Transformation Scenario What if a strong environmental policy that severely limits Alberta s oilsands and electricity industries is implemented? In the Energy Transformation Scenario, the assumption is that a major policy shift results in a new, strong environmental policy which greatly affects the growth of Alberta s energy industries and promotes renewable energy production. In this scenario, restrictions on new oilsands emissions and development are so severe they drastically slow down oilsands development. In this scenario there is an increase in natural gas prices, leading to higher costs for gas-fired generation. Major restrictions on coal-fired generation cause a rapid increase in retirements resulting in a significant need for new cleaner generation. Policies to improve energy efficiency also impact industry as well as residential and commercial load. 7.5.1 Energy Transformation Provincial Outlook Economic In contrast to the Environmental Shift Scenario, in the Energy Transformation Scenario the desire to improve environmental performance outweighs the desire to maintain strong economic growth. Consequently, the new policy impacts the oilsands industry the major economic driver of Alberta. While new growth is restricted, the bulk of existing projects are grandfathered in and are able to maintain their existing size and production. Because of the impact to growth, oilsands development and production in the first 10 years are very similar to the Low Growth Scenario. However, after 10 years, it is assumed that the emergence of new technologies and processes allow the oilsands industry to continue growing again at a modest pace. Overall economic growth in the Energy Transformation Scenario is fairly low compared to the main outlook, as limited oilsands growth impacts the rest of the economy. Energy/Load Energy growth in the Energy Transformation Scenario is low compared to the main outlook. The reduction in growth originates from two sources. First, the impact to Alberta s economy resulting from the strong environmental policy reduces overall demand for electricity across all sectors. Second, it is assumed that the new environmental policy also includes energy efficiency mandates which further reduce electricity demand. Overall, total electricity demand in the Energy Transformation Scenario is similar to the Low Growth Scenario; however, the patterns of consumption are somewhat different. Compared to the Low Growth Scenario, the Energy Transformation Scenario has lower commercial and residential growth but slightly higher industrial and oilsands growth. This is because the primary driver in the Low Growth Scenario is economic, impacting the industrial and oilsands sectors the most, while the energy efficiency impacts in the Energy Transformation Scenario impact the commercial and residential sectors the most. Because the commercial and residential sectors see the greatest reduction in growth compared to the main outlook and other scenarios, the greatest impact geographically in the province is a reduction of load compared to the main outlook in urban areas, especially Calgary and Edmonton. 7.0 Scenarios PAGE 35

Generation Generation development in the Energy Transformation Scenario is characterized by a more aggressive coal retirement schedule and an increased penetration of renewable energy sources during low load growth. Retirements are assumed to be more aggressive than the main outlook with coal plants retiring at either the later of 40 years of operations, or the expiration of a PPA, or one year after the expiration of the PPA if eligible to recover decommissioning costs. The economics around low-emitting forms of energy are improved as a result of incentives from policy, improvements in technology and reduced capital costs. Higher gas prices in the scenario also increase the costs of gas-fired generation, again making renewable forms of energy more attractive. In the first 10 years, approximately 3,700 MW of coal-fired generation is assumed to retire. Given the need to develop baseload generation quickly to offset the retirements, combinedcycle generation is developed. In addition, a stronger policy than in the Environmental Shift Scenario provides further incentives to renewable energy sources and leads to strong development of wind generation. In the second 10 years there are continued retirements with an additional 1,500 MW of coalfired retirements. In addition to combined-cycle, longer lead time generation sources such as hydro are able to develop and meet some of the required energy needs. There is also continued development of renewable sources such as wind generation. Table 7.6-1 compares the Energy Transformation Scenario to the main outlook and other scenarios. 7.6 2014 LTO Results Summary and comparison In the Low Growth Scenario, the main effect of lower growth is reduced load and generation development across the province, but especially in the Northeast Region as oilsands load and cogeneration are most affected. In the Environmental Shift Scenario, there is reduced demand growth in the nearer term as environmental policy impacts development. However, after 10 years, oilsands technology increases due to higher intensity production including electricity-based extraction. The result is significantly higher load growth in the second 10 years. Additional generation development of wind, cogeneration and hydro supports this additional load growth. The impacts from strong environmental policy in the Energy Transformation Scenario cause lower load growth across the province as the economy is impacted from lower oilsands development, and as stronger energy efficiency measures take effect. Generation in the Energy Transformation Scenario shifts towards renewables including wind and hydro, while coal-fired generation is retired at an accelerated rate compared to the main outlook. PAGE 36 7.0 Scenarios

Table 7.6 1: 2014 LTO Load and Generation Comparison (MW) 2019 Main Outlook Low Growth Environmental Shift Energy Transformation Demand AIL Peak 14,274 12,000 13,380 11,777 Coal-fired 5,402 5,402 5,402 5,247 Cogeneration 6,003 4,803 6,153 5,059 Combined-cycle 2,513 1,643 2,113 1,643 Generation Capacity Simple-cycle 1,228 763 1,118 1,053 Hydro 894 894 894 894 Wind 1,751 1,635 2,014 2,014 Other 468 468 468 468 2024 Main Outlook Low Growth Environmental Shift Energy Transformation Demand AIL Peak 16,014 12,689 15,288 12,470 Coal-fired 5,402 5,402 5,402 2,509 Cogeneration 6,302 4,953 6,697 5,144 Combined-cycle 4,001 2,043 2,983 3,783 Generation Capacity Simple-cycle 1,679 1,019 1,769 1,794 Hydro 894 894 894 894 Wind 2,263 1,751 2,791 2,920 Other 498 498 548 783 2034 Main Outlook Low Growth Environmental Shift Energy Transformation Demand AIL Peak 18,519 13,504 18,804 13,568 Coal-fired 2,509 2,509 2,509 929 Cogeneration 6,737 5,153 7,527 5,384 Combined-cycle 8,871 4,921 7,471 4,283 Generation Capacity Simple-cycle 2,399 1,834 2,939 2,074 Hydro 894 894 1,894 2,294 Wind 2,679 2,071 3,777 4,015 Other 864 764 914 1,343 Source: AESO 7.0 Scenarios PAGE 37

Appendix A Main Outlook Detailed Results Table A-1: Annual Energy and Load Outlook Year Industrial (without Oilsands) (GWh) Oilsands (GWh) Residential (GWh) Commercial (GWh) Farm (GWh) Sector Total (GWh) Losses (GWh) Other** (GWh) AIL (GWh) AIL Winter Peak (MW) AIL Summer Peak (MW) 2004* 33,610 6,485 7,559 11,672 1,733 61,060 4,024 175 65,259 9,236 8,578 2005* 33,973 6,695 7,769 12,081 1,705 62,223 3,869 176 66,268 9,580 8,566 2006* 34,042 8,347 8,254 12,733 1,769 65,144 4,048 178 69,371 9,661 9,050 2007* 32,973 8,576 8,539 13,114 1,806 65,007 4,485 167 69,660 9,710 9,321 2008* 31,998 9,431 8,833 13,526 1,803 65,592 4,138 217 69,947 9,806 9,541 2009* 30,950 10,660 9,090 13,534 1,900 66,135 3,595 184 69,913 10,236 9,117 2010* 31,525 11,134 9,071 13,748 1,708 67,186 4,342 196 71,723 10,226 9,343 2011* 31,631 11,917 9,333 14,207 1,828 68,916 4,529 155 73,600 10,609 9,552 2012* 32,768 13,364 9,412 14,596 1,800 71,941 3,432 201 75,574 10,599 9,885 2013* 33,065 14,341 9,678 14,778 1,836 73,699 3,556 202 77,457 11,139 10,063 2014 33,200 15,097 9,959 15,253 1,839 75,349 3,716 245 79,310 11,323 10,421 2015 33,724 16,774 10,153 15,609 1,846 78,106 3,862 245 82,214 11,811 10,765 2016 34,182 19,122 10,343 15,932 1,853 81,432 4,039 245 85,716 12,531 11,170 2017 35,282 22,241 10,527 16,225 1,861 86,136 4,289 245 90,669 13,192 11,799 2018 36,727 24,950 10,708 16,608 1,869 90,862 4,540 244 95,646 13,783 12,390 2019 38,007 27,334 10,889 16,990 1,877 95,097 4,765 245 100,106 14,274 12,938 2020 39,124 29,631 11,068 17,411 1,885 99,119 4,979 246 104,344 14,722 13,429 2021 39,842 31,117 11,244 17,800 1,894 101,896 5,126 244 107,267 15,033 13,865 2022 40,509 32,009 11,416 18,194 1,902 104,031 5,239 244 109,514 15,376 14,148 2023 41,478 32,711 11,586 18,609 1,910 106,294 5,360 244 111,898 15,672 14,460 2024 42,437 33,386 11,754 19,031 1,919 108,526 5,478 244 114,249 16,014 14,731 2025 43,370 33,734 11,925 19,455 1,927 110,411 5,578 244 116,234 16,318 15,048 2026 44,307 34,260 12,089 19,865 1,937 112,458 5,687 245 118,390 16,643 15,327 2027 45,152 34,637 12,252 20,289 1,945 114,275 5,783 244 120,303 16,869 15,627 2028 45,940 35,008 12,413 20,720 1,955 116,036 5,877 245 122,158 17,137 15,817 2029 46,663 35,183 12,575 21,151 1,964 117,536 5,957 244 123,737 17,403 16,083 2030 47,481 35,428 12,737 21,597 1,974 119,217 6,046 245 125,508 17,647 16,329 2031 48,208 35,611 12,900 22,049 1,983 120,751 6,128 245 127,124 17,870 16,554 2032 48,915 35,807 13,062 22,503 1,993 122,281 6,209 245 128,734 18,102 16,760 2033 49,392 35,913 13,224 22,948 2,003 123,481 6,272 244 129,997 18,308 16,975 2034 49,926 36,040 13,386 23,401 2,014 124,766 6,341 244 131,351 18,519 17,167 * Denotes actuals ** Other includes Fort Nelson (supplied by AIES) Note: The data presented in this table are for the Alberta Balancing Authority area which also includes Fort Nelson, British Columbia. Energy and loads are counted once and only once. PAGE 38 Appendix A: Main Outlook Detailed Results

Table A-2: Generation Additions and Installed Capacity (MW) Anticipated generation additions 2019 2024 2034 Forecast Alberta winter peak demand (2014 LTO) 14,274 16,014 18,519 Market reserve margin range 15%-25% 15%-25% 15%-25% Effective generation capacity range 16,415 17,842 18,416 20,018 21,297 23,149 Existing generation capacity (end of 2013) 14,568 14,568 14,568 Effective existing generation capacity (end of 2013) 13,276 13,276 13,276 Retirements 975 975 3,868 Net effective generating capacity after retirements 12,301 12,301 9,408 Expected effective generating capacity additions 4,114 to 5,541 6,115 to 7,717 11,889 to 13,741 Additions by fuel type 2019 2024 2034 Coal-fired 0 0 0 Cogeneration 1,758 2,057 2,492 Combined-cycle 1,670 3,158 8,028 Simple-cycle 530 981 1,701 Hydro 0 0 0 Wind 663 1,175 1,591 Other 45 75 441 Total additions 4,666 7,446 14,253 Total effective additions 4,135 6,506 12,980 Capacity by fuel type 2019 2024 2034 Coal-fired 5,402 5,402 2,509 Cogeneration 6,003 6,302 6,737 Combined-cycle 2,513 4,001 8,871 Simple-cycle 1,228 1,679 2,399 Hydro 894 894 894 Wind 1,751 2,263 2,679 Other 468 498 864 Total effective generation capacity 16,427 18,792 22,300 Total installed capacity 18,259 21,039 24,953 Appendix A: Main Outlook Detailed Results PAGE 39

Appendix B Forecasting Process Inputs Products Additional Information Third-party economic forecast ECONOMIC FORECAST AND ASSUMPTIONS Economic forecast from third-party experts cross-referenced with other economic forecasts to confirm reasonableness and consistency. Historical consumption data ENERGY FORECAST (annual consumption forecast by customer sector) Energy forecasts by customer sector to reflect sector-specific drivers and relationships. STAKEHOLDER CONSULTATION Historical load by POD Distribution Facility Owner (DFO) forecasts Project specific information LOAD FORECAST (hourly load data by POD) SYSTEM LOAD FORECAST On-site generation forecast combined with load forecast to create the system load forecast. Historical growth and load shapes at existing PODs are combined with DFO forecasts and project information. This creates a POD outlook which uses the energy forecast to produce hourly load projections by POD. Generation resource assessments Levelized unit electricity cost Project specific information GENERATION FORECAST (annual capacity addition by resource type) Market-wide assessment of generation requirements and development opportunities by technology and fuel type. Aggregated and tested to ensure market signals support generation development and that forecast load is adequately met. PAGE 40 Appendix B: Forecasting Process

Appendix C Forecast Considerations Introduction This appendix is intended to provide additional background and details of other forecast considerations that were analyzed as part of the creation of the 2014 LTO. Alberta, its electricity industry, regulations, technologies, and economy are constantly changing. To ensure that the 2014 LTO is aligned with current and expected trends, the AESO continually monitors relevant industry developments that could affect the outlook. Factors likely to be key drivers are incorporated into the forecast. Factors that could be key drivers in the future are examined and understood as best as possible so the AESO can prepare in the event trends change. Part of this examination includes the creation of comprehensive forecast scenarios which allow the AESO to quantify the impact of changes to key forecast drivers (see Section 7). The Environmental Considerations Section in this appendix outlines the major development and environmental regulations which can affect future load and generation development. The Energy and Load Section describes some of the key inputs factored into the energy and load forecasts. The Generation Section summarizes the AESO s research into the generation types and costs used as part of the basis of the generation outlook. The AESO continues to track developments and will adjust future Long-term Outlooks as required. This appendix discusses the following forecast considerations related to policy, energy and load, and generation. Appendix C: Forecast Considerations PAGE 41

Table C-1: Forecast Considerations Environmental Drivers Energy and Load Generation Oilsands Development Customer Sector Energy Current Generation Technologies Coal Climate Change Federal policies Provincial policies Demand Side Management Energy efficiency Demand response Oilsands Alternative extraction technologies Electric intensities and efficiencies Upgrading capacity Export Pipelines Natural Gas Wind Hydro Biomass/Other Other Generation Technologies Solar Energy Storage Geothermal Nuclear Levelized Unit Electricity Costs Environmental Considerations The energy industry is affected by a wide range of environmental regulations, both federal and provincial. The 2014 LTO considers only those regulations currently in force at time of writing, with existing policy lending overall direction to the forecast. Policy and regulation are a significant unknown with regard to the long-term forecast. Risks to the 2014 LTO are explored through the development of comprehensive scenarios, which are described in Section 7. Oilsands Development The oilsands sector is the key economic driver of the Alberta economy. The federal government has been considering environmental regulations for the petroleum industry, including the oilsands, since 2011, with industry and provincial consultations continuing at time of writing. The provincial government continues to balance environmental protection with sustained economic growth through frameworks such as the Comprehensive Regional Infrastructure Sustainability Plan (CRISP) 9 and the Provincial Energy Strategy (PES). 10 9 http://www.energy.alberta.ca/initiatives/3224.asp 10 http://www.energy.alberta.ca/initiatives/3082.asp PAGE 42 Appendix C: Forecast Considerations

New technologies and efficiency improvements have reduced the greenhouse gas (GHG) intensity of oilsands production, largely as a result of: Improvements to the energy efficiency of bitumen extraction Fuel switching from petroleum coke to natural gas and replacement of grid electricity by onsite heat and electricity cogeneration Upgrading efficiency gains from optimization and integration of processes Use of nitrogen oxide burners, sour water treatment equipment and flue gas desulphurization The addition of newer, more efficient facilities Climate Change Policy Environmental concerns present unique forecasting challenges due to the continuously evolving nature of regulation. Although the Canadian government is now implementing a sector-by-sector regulatory approach to reduce greenhouse gas emissions, uncertainty still exists regarding GHG regulation at time of writing. Federal Climate Change Policy Canada is taking a sector-by-sector regulatory approach toward achieving its commitment to reduce economy-wide greenhouse gas emissions to 17 per cent below 2005 levels by 2020 under the Copenhagen Accord. Greenhouse gas emissions from coal-fired electricity are responsible for approximately 11 per cent of Canada s total GHG emissions, 11 and the federal government has responded to this challenge with regulations described below. The government is continuing to work on regulations for other major sources of GHG emissions, including gas-fired electricity generation and the oil and gas sector. Coal-fired Electric Generation In September 2012 the Canadian federal government enacted the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, 12 which will reduce carbon dioxide (CO2) emissions from the country s roughly 13 gigawatt (GW) coal-fired generating fleet. In the first 21 years, the regulations are expected to result in a cumulative reduction in GHG emissions of about 214 megatonnes equivalent to removing some 2.6 million personal vehicles per year from the road. 13 The regulation allows existing coal units up to 50 years of operational life before they must either retire or retrofit with carbon capture and storage (CCS) technology. Given the current economics of CCS, the 2014 LTO anticipates that most units will retire by 2034. With the first significant retirements occurring in 2019, the regulation allows ample time for constructing replacement generation. 11 http://www.ec.gc.ca/default.asp?lang=en&n=714d9aae-1&news=4d34ae9b-1768-415d-a546-8ccf09010a23 12 http://www.gazette.gc.ca/rp-pr/p2/2012/2012-09-12/html/sor-dors167-eng.html 13 http://www.ec.gc.ca/default.asp?lang=en&n=714d9aae-1&news=4d34ae9b-1768-415d-a546-8ccf09010a23 Appendix C: Forecast Considerations PAGE 43

Canada s CO2 performance standard is similar to the U.S. Environmental Protection Agency s (EPA) proposed standard for new baseload generators. In both cases new supercritical coal units must capture about half their CO2 emissions to comply, while natural gas-fired combined-cycle can achieve the same standard without CCS. Renewables The ecoenergy for Renewable Power program 14 was launched in April 2007 to encourage the generation of electricity from renewable energy sources such as wind, low-impact hydro, biomass, photovoltaic and geothermal energy. Although the program ended on March 31, 2011, many projects with contribution agreements will continue to receive payments up to March 31, 2021. At March 31, 2011, 104 projects qualified for funding under the program, representing investments of about $1.4 billion over 14 years and almost 4,500 megawatts of renewable power capacity. 15 However, the tax incentives for renewable and emerging projects remain in place. 16 Through Sustainable Development Technology Canada (SDTC), the federal government has supported more than 245 clean technology projects that are part of an SDTC portfolio now valued at more than $2 billion, of which $1.4 billion is leveraged from partners in the private sector. Building on this, $325 million in funding over eight years was earmarked for SDTC in the 2013 federal budget to support the development and demonstration of new clean technologies, including: Electrical vehicle charging stations A system to convert municipal solid waste into energy-rich gas to produce heat and electricity in remote and rural areas Wind hybrid power plants Federal Carbon Capture and Storage (CCS) Initiatives Over the past five years, the Government of Canada has committed over $500 million to carbon capture and storage (CCS) initiatives. 17 One of these initiatives is the provision of $240 million 18 of research funds towards the Boundary Dam CCS project in Saskatchewan. Once completed, this project will be one of the world s first and largest commercial scale CCS projects for coal-fired electricity. The total cost of the project is expected to be $1.24 billion, of which approximately $180 million has already been spent. SaskPower announced in October 2013 that the project was $115 million over budget. 14 https://www.nrcan.gc.ca/ecoaction/14145 15 http://www.nrcan.gc.ca/ecoaction/6444 16 CCA 43.1 & 43.2; CRCE; SR&ED and ITCs 17 http://www.climatechange.gc.ca/default.asp?lang=en&n=72f16a84-1 18 http://www.climatechange.gc.ca/default.asp?lang=en&n=72f16a84-1 PAGE 44 Appendix C: Forecast Considerations

Air Quality Management System The Air Quality Management System (AQMS) is a comprehensive approach for improving air quality in Canada and is the product of collaboration by federal, provincial and territorial governments and stakeholders. It includes: New Canadian Ambient Air Quality Standards (CAAQS) to set the standard for outdoor air quality management across the country A framework for air zone management within provinces and territories that enables action tailored to specific sources of air emissions in a given area Regional airsheds that facilitate coordinated action where air pollution crosses a border Industrial emission requirements that set a base level of performance for major industries in Canada (BLIERs) Improved intergovernmental collaboration to reduce emissions from the transportation sector On October 11, 2012, the provinces, with the exception of Québec, agreed to begin implementing the Air Quality Management System. Although Québec supports the general objectives of AQMS, it will not implement the system since it includes federal industrial emission requirements that duplicate Québec s Clean Air Regulation. Canadian Ambient Air Quality Standards Canadian Ambient Air Quality Standards (CAAQS) will be established as objectives under the Canadian Environmental Protection Act, 1999, and will replace existing Canada-wide air standards. Standards for fine particulate matter and ground level ozone 19 have been developed and were published to Canada Gazette in May 2013. Work has begun to assess the health and environmental impacts of nitrogen dioxide and sulphur dioxide. Base-Level Industrial Emissions Requirements Base-Level Industrial Emissions Requirements (BLIERs) are intended to ensure that all significant industrial sources in Canada, regardless of where facilities are located, meet a good base level of performance. BLIERs are a requirement under the Air Quality Management System (AQMS). BLIERs are quantitative or qualitative emissions requirements proposed for new and existing major industrial sectors and some equipment types. These requirements are based on what leading jurisdictions inside or outside Canada are requiring of industry in attainment areas, or airshed zones adjusted for Canadian circumstances. BLIERs are focused on nitrogen oxides, sulphur dioxide volatile organic compounds (VOCs), and particulate matter (PM). 20 For electricity generators, BLIERs would establish stack emission intensity limits. Similar to the federal Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, BLIERs would require control equipment and would apply on a unit-by-unit basis, with no trading. At time of writing, BLIERs for electricity generators are still being drafted. 19 http://www.ccme.ca/assets/pdf/caaqs_and_azmf.pdf 20 http://www.ccme.ca/assets/pdf/cams_proposed_framework_e.pdf for proposed levels Appendix C: Forecast Considerations PAGE 45

Demand-side Management/Energy Efficiency New demand-side management and energy efficiency technologies and regulations have the potential to affect the long-term forecast. Canada s Energy Efficiency Act and Regulations eliminate the least energy-efficient products from the Canadian market. Of the many federal initiatives, the new light bulb standard has the greatest potential impact on the LTO. Lighting Standards In December of 2008, as part of its effort to reduce energy consumption and greenhouse gas emissions, the Government of Canada established new energy-efficiency regulations to phase out the use of inefficient light bulbs. On April 16, 2011, an amendment was proposed to delay the implementation of the standard by two years. This delay was approved and published on November 9, 2011. As a result, the standard will affect 75- and 100-watt bulbs manufactured after January 1, 2014, and 40- and 60-watt bulbs manufactured after December 31, 2014. 21 The standard for lighting efficiency is a performance or technology neutral standard. It does not prescribe any particular light source technology and is set at a minimum performance level that ensures a wide array of choices will be available to Canadians once it comes into effect. It applies to bulbs imported in Canada or sold inter-provincially and will phase out standard, medium screw-base, A-shape incandescent bulbs. The U.S. and a number of other countries are either developing or have already implemented similar standards for the elimination of the least efficient light bulbs from their markets. Provincial Climate Change Policy Alberta s current climate change strategy, Responsibility/Leadership/Action, was published in January 2008. 22 It targets a reduction of annual emissions by 20 million tonnes (Mt) below the business-as-usual level by 2010 by identifying three distinct approaches: Energy conservation and efficiency Carbon capture and storage (CCS) Greening energy production The plan anticipates that two thirds of the anticipated emission reductions are to come from CCS. The provincial government released Clearing the Air: Alberta s Renewed Clean Air Strategy 23 in 2012, which links with Alberta s established Comprehensive Air Quality Management System 24 (CAMS), the decision making process established by the provincial Clean Air Strategic Alliance (CASA). 21 http://oee.nrcan.gc.ca/regulations/17724 22 http://environment.gov.ab.ca/info/library/7894.pdf 23 http://environment.gov.ab.ca/info/library/8692.pdf 24 http://casahome.org/desktopmodules/bring2mind/dmx/download.aspx?command=core_download&entryid=898&portali d=0&tabid=78 PAGE 46 Appendix C: Forecast Considerations

While the main instrument of provincial climate change policy is the Specified Gas Emitters Regulation (SGER), Alberta has initiated a number of other programs, including: Grants supporting CCS technology Government purchase of green power Micro-generation Regulation Light it Right program Renewable Fuels Standard Regulation Bioenergy Producer Credit Program GreenTRIP, hybrid taxi and Trucks of Tomorrow programs Rebates for energy-efficient home upgrades Initiatives for meeting LEED standards for public buildings On-Farm Energy Management program Clean Air Strategic Alliance (CASA) The Clean Air Strategic Alliance (CASA) is a multi-stakeholder partnership established in 1994 as a way to manage air quality in Alberta. CASA is composed of representatives from industry, government and non-government organizations to provide strategies to assess and improve air quality using a collaborative consensus process. CASA is tasked with the implementation of the Comprehensive Air Quality Management System (CAMS) for Alberta. In 2003 CASA finalized An Emission Management Framework for the Alberta Electricity Sector (the Framework) that was accepted by the Government of Alberta and implemented through regulations, standards and facility approvals such as SGER. To ensure continuous improvement and to keep the Framework timely and relevant, a formal review process is to be undertaken every five years. The first five-year review occurred in 2008 and the second review commenced in 2013. This review includes a multi-stakeholder group consisting of industry, government, non-government organizations, and communities with an interest in the electricity sector. CASA is responsible for responding to the difference between the Framework, Environment Canada s proposal for Base-Level Industrial Emissions Requirements (BLIERs) for existing coal-fired electricity generation units, and the Canadian government s Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations. At time of writing, CASA was continuing to address stakeholder concerns that the requirement to implement BLIERs at existing coal-fired facilities would have the effect of negating much of the existing Alberta framework. 25 25 CASA Annual Report: 2012, pg. 19 Appendix C: Forecast Considerations PAGE 47

Specified Gas Emitters Regulation While federal regulations set minimum standards, Alberta also has a provincial GHG regulation. Alberta s current GHG regulation, the Alberta Specified Gas Emitters Regulation (SGER), 26 was enacted in 2007 and is set to expire in 2014. The regulation requires industrial facilities, including electricity generators that emit more than 100,000 metric tonnes of GHG per year to reduce their corresponding emissions intensity by 2 per cent per year up to a limit of 12 per cent. The use of credits and financial contributions to the Climate Change and Emissions Management Fund 27 which invests in projects related to Alberta s climate change strategy is also allowed as a compliance mechanism. Since the implementation of the regulation in July 2007 to the end of March 2013, the Alberta Emissions Offset Registry (AEOR) has registered a total of 137 projects and serialized almost 28 million tonnes (Mt) of GHG emission reductions or removals through registration of offset projects. 28 SGER is currently under review by the provincial government before expiry in 2014 to ensure alignment with federal policy initiatives. 29 Alberta Carbon Capture and Storage (CCS) Initiatives The provincial government has committed a total of $1.3 billion over 15 years to fund two large-scale CCS projects; the Alberta Carbon Trunk Line project and the Quest project. It is anticipated that these projects will reduce Alberta s GHG emissions by 2.76 million tonnes annually beginning in 2015. 30 The Alberta Carbon Trunk Line project is a 240 km pipeline that will transport CO2 from a fertilizer plant and a bitumen refinery to producing oil fields in central Alberta for enhanced oil recovery. The Quest project is designed to capture and store 1.2 million tonnes of CO2 annually from Shell Canada s Scotford oilsands upgrader and expansion near Fort Saskatchewan. Two power generation projects were selected to receive funding from the Alberta government; Swan Hills Synfuels ISCG generation facility and TransAlta Corporation s Project Pioneer. These projects have since been cancelled but details on Project Pioneer and the feasibility of the project are available in a final project report. 31 Given the estimated costs related to CCS, no CCS is assumed for generation projects in the 2014 LTO. 26 http://environment.alberta.ca/01838.html 27 http://ccemc.ca/ 28 http://carbonoffsetsolutions.climatechangecentral.com/policy-amp-regulation/alberta-offset-system-compliance-aglance/2012-compliance-year 29 Stakeholder Presentation December 2012 30 http://www.energy.alberta.ca/initiatives/1438.asp 31 http://www.transalta.com/newsroom/feature-articles/2013-05-24/project-pioneer-publishes-its-final-report-pioneer-still-sharin PAGE 48 Appendix C: Forecast Considerations

Table C-2: Environmental Considerations Summary 32 33 34 35 36 37 38 39 40 41 42 43 Policy Federal Provincial CO2 Emissions Coal-fired Regulation 32 (2012) SGER 33 (2007) Non-CO2 GHG Emissions BLIERs 34 (in progress) CAMS 35 monitoring Renewable Energy Tax incentives: (CCA, 36 CRCE, 37 SR&ED 38 ) In-province tradable green offsets via SGER Emerging Technology Demand Side Management/ Energy Efficiency (DSM/EE) SDTC 39 ($325 million budgeted in 2013) CCEMF 40 ($213 million in 2013) 41 Energy Efficiency Regulations C3 42 targeted programs 43 Energy and Load Forecast Considerations Customer Sector Energy The AESO forecasts energy consumption in the province by individually analyzing and forecasting the electricity consumption of five customer sector types. The forecasts are based upon economic, demographic and end-use data, and project and customer information collected from a variety of sources. The energy sector models are based on models that were reviewed by a third-party independent load forecast expert. The models also use economic variables from The Conference Board of Canada as inputs, ensuring consistency with the 2014 LTO economic outlook. Table C-3 outlines the key drivers for each of the sectors. 32 Federal Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations 33 Alberta Specified Gas Emitters Regulation 34 Base-Level Industrial Emission Requirements 35 Comprehensive Air Management System 36 Capital Cost Allowance Classes 43.1, 43.2, 49, 7 37 Canadian Renewable & Conservation Expense 38 Scientific Research and Experimental Development 39 Sustainable Development Technology Canada 40 http://ccemc.ca/media_release/climate-change-and-emissions-management-ccemc-corporation-releases-annual-reportccemc-funding-51-clean-tech-projects-valued-at-more-than-1-56-billion/ 41 Climate Change and Emission Management Fund 42 Includes: Alberta s Home Electricity Use Evaluation; municipal rebates; BioFleet; Carbon Offset Solutions; Heartland Energy Mapping Study; Alberta Industrial Energy Efficiency Program 43 http://c-3.ca/projects/ Appendix C: Forecast Considerations PAGE 49

Table C-3: Electricity Consumption Drivers Customer Sector Drivers 2013-2019 Growth Rate 2013-2024 Growth Rate 2013-2034 Growth Rate Industrial (without Manufacturing GDP 2.5% 1.9% 1.8% Oilsands) Oilsands production 7.0% 5.6% 3.9% Natural gas production -4.3% -3.0% -1.8% Non-oilsands crude oil production -2.1% -2.2% -2.2% Oilsands Oilsands production 7.0% 5.6% 3.9% Electrical per barrel of in situ, mining, and upgrading 4.6% 2.7% 0.9% Commercial Alberta service-producing GDP 2.8% 2.8% 2.6% Residential Real Disposable Income 2.4% 2.3% 2.1% Energy Efficiency Improvement (weighted-average across end uses) 0.7% 0.5% 0.2% Population 1.7% 1.6% 1.4% Farm Acres of irrigated land 0.5% 0.5% 0.5% Agricultural GDP 1.8% 1.9% 2.0% Demand-side Management Demand-side Management (DSM) refers to activities and initiatives undertaken to influence the level or timing of customer electricity demand. DSM can be broken into several subcategories. Energy efficiency and conservation are initiatives aimed to reduce overall electricity demand. Demand response programs typically involve a temporary reduction in the demand for electricity by load entities whether for reasons of reliability or through price signals and other incentives. Energy Efficiency Energy efficiency and conservation programs and initiatives are generally designed to reduce overall electricity demand and can vary greatly in size and scope. The pace of energy efficiency changes depends on policy as well as the economics of investments in energy efficiency and conservation. The AESO incorporates anticipated effects of energy efficiency through its Statisticallyadjusted End-Use Residential (SAE) model which was developed in consultation with Itron Inc. The SAE model uses residential end-use data including appliance and lighting saturation rates and other household data for Alberta from Natural Resources Canada s Comprehensive End-Use Database. 44 That data is combined with end-use efficiency projections from the U.S. Energy Information Administration (EIA) 45 and economic forecasts from The Conference Board of Canada. Through combining that data, estimates of residential electricity use are created and then statistically adjusted using historical actual residential energy use. The result is a comprehensive model that factors in economic trends aligned with the economic outlook, Alberta residential end-use data, and expected trends in household energy efficiency. 44 http://oee.nrcan.gc.ca/corporate/statistics/neud/dpa/trends_res_ab.cfm?attr=0 45 http://www.eia.gov/forecasts/archive/aeo13/sector_residential.cfm PAGE 50 Appendix C: Forecast Considerations

The residential energy forecast resulting from the residential SAE model are shown in Appendix A. These results were compared with the econometric model used in prior AESO forecasts. Generally, the results were in line; however, the SAE model is able to capture the effects of the recent federal lighting standards. Therefore, the residential forecast is slightly lower compared to an equivalent econometric-based residential forecast. The AESO continues to monitor energy efficiency initiatives and progress, and will continue to adjust its forecast processes accordingly. Demand Response There are a number of different demand response type programs that vary with intended purpose. The AESO has implemented a combination of demand response programs to assist in managing or preventing emergency system operating conditions: Load Shed Service for imports (LSSi) an ancillary service that enables an increase in import capacity on the B.C. intertie by mitigating potential frequency drops caused by the sudden loss of the intertie and during periods of high imports Demand Opportunity Service (DOS) an opportunity transmission service with regulated rates for each level of interruption (seven minutes and one hour) Supplemental operating reserve (SUP) ancillary service available to arrest frequency decline but not required to respond directly to frequency deviations. This service can be provided by load or generation These demand response programs are in place for reliability purposes. The 2014 LTO does not assume that reliability issues will materially affect future load. In addition to reliability-based demand response programs, the Alberta market also has approximately 300 MW of voluntary price-responsive load, primarily from a small set of industrial customers. The ability for load to respond to the energy market depends on the ability of load to react to market price signals and to adjust consumption in response to those signals. At approximately 300 MW, price-responsive load currently represents about three per cent of AIL. Oilsands The oilsands sector is a key driver of the provincial economy and a pivotal industry for electricity demand and supply. Several forecast considerations were examined related to the oilsands sector, including alternative extraction technology, increasing electricity intensities and efficiencies, and increased upgrading capacity. Alternative Extraction Technologies With 20 per cent of current recoverable oilsands reserves located near the surface, roughly 50 per cent of current bitumen production is extracted using a strip-mining process. Approximately 80 per cent of recoverable deposits are too deep for surface mining extraction techniques, and so the remaining 50 per cent of current production is extracted using a thermal extraction process known as Steam Assisted Gravity Drainage (SAGD). Near-term oilsands growth is expected to be largely driven by SAGD operations. Appendix C: Forecast Considerations PAGE 51

Environmental concerns such as water usage and GHG emissions are encouraging the development of new extraction technologies. These new technologies have the potential to affect demand for electricity in the oilsands. The AESO monitors the development of these technologies and has incorporated their potential impact in the 2014 Long-term Outlook. Electric heating is one such technology. It is a process where electric energy is used to stimulate and heat bitumen deposits. Depending on the electrical current applied, the energy can be transferred numerous ways: dielectric heating, resistive heating, conductive or induction heating. A number of electric heating processes are currently in early development, including Thermal Assisted Gravity Drainage (TAGD) by Athabasca Oil Corporation (AOC), Electro-Thermal Dynamic Stripping Process (ET-DSP) by E-T Energy, and electromagnetic heating (EM-SAGD) being developed by Siemens AG. With no steam requirements, and considerably lower reservoir temperatures, electric heating technologies aim to access resources unreachable with current SAGD technology. Early indications suggest that electric heating technologies will require upwards of ten times the electricity requirements of current SAGD operations. While several of these technologies are in pilot or demonstration phases, a commercial deployment timetable has not yet been determined for these technologies. Hybrid solvent extraction together with electric heating technologies are also being developed, with the objective of lowering energy intensity by operating at 50 degrees Celsius and requiring little amounts of water. This technology is being developed in partnership between operators and technology providers including Nexen Inc., Laricina Energy Inc., Suncor Energy Inc. and Harris Corporation. In situ combustion technologies produce bitumen using heat generated within the reservoir from combustion. Heat from combustion reduces the bitumen s viscosity and mobilizes it. The burning progresses through the reservoir, mobilizing the oil and combustion gases, which then drain to the production well zone by gravity. Potential benefits over current SAGD processes include lower water demand and lower GHG emissions. Petrobank Energy and Resources Ltd. s Toe-to-Heel Air Injection (THAI) method and AOC s combustion overhead gravity drainage (COGD) are both examples of this technology. A technique similar to SAGD injects solvents such as ethane, propane or butane instead of steam into the oilsands reservoir to mobilize the bitumen. These processes have the potential to eliminate natural gas requirements for heating water into steam, thereby reducing GHG emissions and water consumption. Vapour extraction process (VAPEX) being explored by industry and solvent aided process (SAP) developed by Cenovus Energy Inc. are examples of this technology. The AESO anticipates near-term growth in the oilsands to occur using existing mining and SAGD technologies. Over the longer term, the technologies discussed above could potentially develop on a commercial scale, causing a measurable impact to oilsands electricity consumption and generation. Electricity consumption could be greatly increased if electric heating production techniques prove successful. At the same time, cogeneration development would be reduced if less steam is required for production, due to in situ combustion, solvent or electric heating techniques. The impact of these new technologies remains uncertain at this time; however, their development is closely followed and will be incorporated into future forecasts as they evolve. PAGE 52 Appendix C: Forecast Considerations

Electricity Intensities and Efficiencies The AESO conducts significant research into oilsands electricity intensities and efficiencies as part of its forecast process. As a result of its research, the AESO finds that, in general, oilsands electrical intensities are more likely to rise in the future than decrease. The primary use of electricity at oilsands sites is for motors which are typically used to drive pumps. Oilsands sites move large quantities of bitumen, water, steam and other liquids using pumps and compressors driven by electric motors. As sites expand, and distances from central processing facilities to wells increases, materials need to be transported greater distances which increases load. The introduction of electrical submersible pumps (ESPs) to reduce steam-to-oil ratios also increases load. As discussed, new technologies are currently being tested such as solvent-assisted SAGD which require the addition of injectors and pumps. These would also increase electric load. Other new electricity-based extraction techniques are being tested at pilot projects. If successful, these technologies could significantly increase the average electrical intensity of the oilsands industry. Environmental considerations could also increase electrical intensities. Higher elevation tailings ponds would increase pumping load, as would centrifuges, an alternative to tailings ponds. Any carbon capture equipment added to a site would increase load, as would equipment added to increase the amount of water recycling at sites. Factors which can decrease electrical intensities are fewer. Part of the reason for this is the electrical motors used at oilsands sites are already very efficient. However, there is some opportunity for efficiency gains through the use of variable speed motors as a replacement for multiple motors. Also, improved extraction efficiency could reduce electrical intensity. For example, improved well-pairing communication between well pairs allows for the wells to share heat and pressure which can lower the need to pump steam, thus reducing the pumping load required to extract a given barrel of bitumen. Alternative tailings solutions such as Suncor s TROTM process, which can speed up and improve tailings reclamation, may also reduce electricity demand. 46 The AESO finds that, based on its assessment of oilsands electrical intensities, there are more factors that could increase than decrease electrical intensity of the oilsands. Slight growth in the electrical intensity of the oilsands is forecast in the 2014 Long-term Outlook and is reflected in its oilsands energy forecast; however, it is within a historical range. The growth in electrical intensity is based upon information from individual project information combined with third-party forecasts of oilsands production. The forecast electrical intensities are also compared with historical intensity trends in order to assure consistency and reasonableness. 46 http://www.suncor.com/en/responsible/3229.aspx Appendix C: Forecast Considerations PAGE 53

Efficiency efforts in the oilsands are driven by a need to minimize costs. This implies that when companies seek to lower their costs, they will spend capital where it will have the strongest cost-savings effect. Since natural gas represents a significantly larger share of costs than electricity, oilsands producers tend to focus on lowering their steam-oil ratios as much as possible, and in some cases this may mean increasing electricity consumption. Upgrading Capacity Upgrading is the process of converting heavy oil such as bitumen into more easily used hydrocarbon derivatives such as synthetic crude oil. Currently, all mined bitumen and 11 per cent of all in situ bitumen is upgraded to synthetic crude oil in Alberta. There are five upgraders in the province, one under construction and another undergoing expansion. The first phase of North West Redwater Partnership s 47 231,000 barrel per day upgrader is under construction in the Fort Saskatchewan area with support from the Alberta government under the Bitumen Royalty-In-Kind (BRIK) program. 48 Canadian Natural Resources Limited is currently working on a phased-in expansion of its Horizon site, which will increase upgrading capacity from 110,000 to 250,000 bbl/d. The decision to build upgrading facilities in Alberta depends on the long-term profitability of supplying synthetic crude oil, the light-heavy differential, and government programs that support development. Light-heavy differential refers to the difference between the price of light crude and heavy oil. The price of light crude needs to be approximately 30 per cent higher than the price of heavy oil, and sustained for a period of time, for upgraders to break even. These economic considerations are weighed against the costs of transporting the heavy crude to other markets. Major influences on the cost of transporting heavy crude to other markets to be refined are the price and availability of the diluents needed for pipeline transport. Based on industry assessments of the future of upgrading in Alberta, it is generally expected that upgrading will not be sufficiently economic for new upgraders to be built beyond those currently planned over the next 20 years. The cancellation of Suncor s Voyageur upgrader in March 2013 due to challenging economics supports this outlook. 49 However, it is possible that government support such as the BRIK program will be implemented to support additional upgrading capacity. In the event additional upgraders are constructed, they have the potential to add large, concentrated pockets of electric load within the province. Based on data from current and expected upgraders, an upgrader generally uses between 40 MW and 120 MW per 100,000 barrels per day of upgrading capacity, depending on technology choice and products created. 47 In February 2011, North West Upgrading entered into a 50/50 joint venture partnership with Canadian Natural Resources Limited. This collaboration is now called North West Redwater Partnership. 48 http://www.energy.gov.ab.ca/brik.asp 49 http://www.cbc.ca/news/business/suncor-cancels-proposed-voyageur-upgrader-1.1362462 PAGE 54 Appendix C: Forecast Considerations

Export Pipelines There are a significant number of pipelines either under development or about to develop to support the growth in oilsands production as well as to move other natural gas and petroleum-based products. Most are intra-alberta pipelines which have a high likelihood of being constructed. However, the large bitumen-exporting pipelines require special consideration. These large export pipelines are subject to greater regulatory uncertainty than intra-alberta pipelines. They also have large potential loads which can dramatically alter regional load forecasts. The AESO assessed the likelihood of these pipelines entering service based on third-party industry information (including assessments by PIRA Energy Group and IHS CERA) and decided to include three of the four major new export pipelines explicitly in the 2014 LTO. The remaining pipeline (Northern Gateway) was not included due to industry pessimism that it will be approved within the next few years; however, its future load potential was analyzed and studied as a sensitivity in case it does proceed. This strategy allows the 2014 LTO to be aligned with industry expectations of pipeline development while allowing the AESO to be prepared in the event that development occurs differently. The overall AESO export pipeline strategy is outlined in Table C-4 below. Table C-4: AESO Export Pipeline Forecast Strategy Project Capacity In Service Date AESO Strategy TransCanada Keystone TransCanada Keystone XL TransCanada Energy East Conversion Line Kinder Morgan TransMountain Pipeline Expansion Enbridge Northern Gateway Enbridge Clipper (Line 67) 590,000 bbl/d In service N/A 830,000 bbl/d Late 2015 Included late 2015 1,100,000 bbl/d End of 2017 to early 2018 Included 2017 +590,000 bbl/d 2017 Included 2017 520,000 bbl/d Late 2017 Not in main forecast but studied as sensitivity +120,000 bbl/d Mid-2014 Included 2014 Appendix C: Forecast Considerations PAGE 55

Generation Forecast Considerations As part of its forecast process, the AESO evaluates the potential of various forms of generation. This evaluation helps guide the AESO to understand which forms of technology are most and least likely to develop. Figure C-1 shows the type and location of existing generation sources in Alberta. Figure C-1: Type and Location of Generation in Alberta Fort McMurray Area Detail Calgary Area Detail Wabamun / Edmonton Area Detail Coal Gas Cogeneration Hydro Wind Other Major Transmission Lines Source: AESO PAGE 56 Appendix C: Forecast Considerations

Existing Technologies Coal Generation As of December 31, 2013, Alberta has six coal-fired power generation facilities with a total installed capacity of 6,271 MW. This represents 43 per cent of the installed capacity, with the majority located in the Wabamun area. Alberta s large coal reserves are estimated to be 33 billion tonnes, 50 equivalent to 1,000 years of supply at the province s current production rate. A significant portion of the reserves can be mined using open-pit methods. These coal reserves arc from northwest of Edmonton to southeast of Calgary with coal quality declining from northwest to southeast. Not all of the coal in Alberta would be economically viable for power production. In 2012 the Canadian federal government enacted the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations. The regulation allows existing coal units up to 50 years of operational life before they must either retire or retrofit with carbon capture and storage (CCS). Additionally, new units would be required, starting in 2015, to meet a 420 kg/mwh emission level that is roughly equivalent to a natural gas combined-cycle unit. This means new units would need to implement carbon reducing technologies. Given the current economics of CCS, development of new coal-fired generation is not expected to occur. Natural Gas Generation Alberta had 5,892 MW of gas-fired generation as of December 31 2013, consisting of 4,245 MW of cogeneration, 843 MW of combined-cycle, and 804 MW of simple-cycle generation. Cogeneration is located at industrial sites, with a large portion of the generation in the Northeast Region of the province. Combined-cycle and simple-cycle generation have flexibility in location siting and are found throughout the province. The 850 MW combinedcycle Shepard Energy Centre is also expected to energize in 2014 with commercial operation in 2015. The resource potential of gas-fired generation is large. The technology is mature, has location flexibility, relatively low GHG emissions, and good economics. There are also few barriers to its development. Gas-fired generation plays an important role in the Alberta electricity market by providing reliable baseload, flexible mid-range, and peaking capacity. The main driver of cogeneration growth is related to increases in industrial activities. As large industry develops and there is need for both heat and energy, cogeneration is a suitable technology. Combined-cycle generation provides flexible baseload generation. It provides larger amounts of power for the market and can serve as a replacement for retiring coal-fired units. Given options around baseload generation such as nuclear, hydro, clean coal and others, combined-cycle is the expected choice for baseload generation in the future as it has the fewest barriers and lowest levelized costs of assessed technologies. Simple-cycle units have a short start-up time and the ability to ramp up and down rapidly, making them well suited for providing peaking capacity and operating reserves. Simple-cycle generation is an important part of any electrical system as the fast-ramping characteristic is valuable. 50 ERCB, ST98-2011: Alberta s Energy Reserves 2010 and Supply/Demand Outlook 2011-2020, June 2011 Appendix C: Forecast Considerations PAGE 57

Wind Generation As of December 31, 2013 there were 16 transmission-connected wind farms operating in Alberta, with a total capacity of 1,088 MW, representing nine per cent of the province s total installed capacity. There are two additional wind projects expected to commission in 2014 totalling 350 MW. The majority of the wind farms are located in southern Alberta in the Pincher Creek area, with two facilities located in the Central Region. There are three areas in Alberta where wind speeds are attractive for the development of wind facilities. These locations are in the South and Central Regions and a smaller area in the Northwest Region of the province. The theoretical potential of wind development in Alberta is large. In a 2013 study on potential wind development in Alberta, 51 it was estimated that there is 4,000 MW of wind potential with a capacity factor above 40 per cent, while there is 32,000 MW of wind potential with a capacity factor above 35 per cent. The development of wind depends on several considerations including comparable cost economics, green attributes, and provincial, federal and U.S. policy. As such, the main drivers of wind are the expected long-run economics, including impact from policy, and currently developing projects. While wind has the second lowest levelized cost of the technologies assessed, it typically receives lower average revenue than other asset types. This is because wind is a price-taker and its generation displaces marginal units from the merit order, thereby lowering the system marginal price. Policy supporting renewable sources of energy can help the economics of wind, as can market-based mechanisms such as the AESO s project to make wind dispatchable, currently in development. Depending on policy, the relative economics or the market prices received can be improved. Various policies have supported the development of wind over the last 10 years in Alberta. Examples of these include the ecoenergy for Renewable Power program and the Specified Gas Emitters Regulation. Policy in the U.S. as well as individual company policy have also supported wind development in Alberta. Hydroelectric Generation Alberta s hydro capacity is 894 MW and represents six per cent of the total installed capacity in the province. Facilities are primarily legacy units developed prior to market deregulation, and they provide operating reserves and peaking capacity. The largest units are the Bow River hydro system, the Brazeau hydro plant and the Bighorn hydro plant. Future hydro potential is possible throughout the province, with the majority of potential on the Athabasca, North Saskatchewan, Peace, Slave and South Saskatchewan River basins. In a report to the Alberta Utilities Commission in 2010, 52 the ultimate annual energy potential was estimated at 53,000 GWh, or 10,000 MW of capacity at a 60 per cent capacity factor. Of this total ultimate developable energy potential, only 20 per cent of this value was estimated to be developed in the next 30 years. Depending on the capacity factor assumed, this means 1,500 MW to 6,000 MW of hydro capacity could be developed. 51 Solas Energy Consulting, Alberta WindVision Technical Overview Report, 2013, pg. 15 52 http://www.energy.gov.ab.ca/electricity/pdfs/auchydroelectricstudy.pdf PAGE 58 Appendix C: Forecast Considerations

Biomass/Other Generation Alberta currently has 423 MW of other generation capacity fueled by biomass and waste heat. The majority of this capacity is located in northern Alberta, although a small amount can be found in central and southern Alberta. Biomass fuel resources are available in Alberta largely from the forestry industry (industrial and commercial wood residues) and the agricultural sector (crop and livestock waste). In some cases, these facilities are able to run cogeneration units producing both steam and electricity, increasing overall industrial efficiency. Power production from biomass power facilities typically runs as a baseload generator. Generation from biomass is generally restricted to locations at the fuel source to eliminate transportation costs. The potential for new biomass generation is expected to come from relatively small installations. The development of biomass generation will be influenced by the ability to economically utilize any waste material from processes. This could be further incented through government policy or through an increase in the costs to other fuel sources such as natural gas. Other Technologies Solar Alberta has strong solar resources with photovoltaic potential of approximately 1,200 kwh per year per installed kw in Calgary and Edmonton. CanSIA has estimated that between 9,000 MW and 15,000 MW could be developed within Canada by 2025. 53 While no largescale transmission-connected solar facilities have developed, there is potential. Overall, opportunities exist for smaller residential and commercial development, rural applications, and large-scale transmission-connected facilities. Drivers for the development of solar can be split into smaller applications of 1 MW or less, and large transmission-connected facilities. Smaller applications fall under the Alberta Micro-generation Regulation. Through this regulation, which began in 2009, Alberta has seen 4 MW of solar develop to the end of 2013. Given this amount of interest with little direct policy supporting it, and with the expectation that the solar industry will grow, small solar applications can be expected to continue developing, growing at least as fast as has been seen. Policy could be implemented that would increase the amount of residential and commercial solar. This impact of policy has been recognized in other locations around the world. For the development of large-scale solar, the main driver is around relative costs. Either a decrease in solar costs or an increase in costs of other technologies could increase the development of solar. Decreases in the cost of solar could come from technology improvements or from supportive policy. Increases in the cost of other technologies could come from increased fuel costs, such as higher natural gas prices, or from increased costs on emissions. Large-scale solar is included in the main outlook. Nominal amounts of solar are included in the Energy Transformation Scenario grouped into the Other category. 53 Solar Vision 2025, CanSIA, December 2025 Appendix C: Forecast Considerations PAGE 59

Energy Storage Alberta interest in utility-scale energy storage has increased in recent years. The AESO has received applications for connection of multiple energy storage projects including batteries, compressed air energy storage and pumped hydro. In addition, in September 2012, the AESO launched an energy storage initiative which will review the effectiveness and applicability of existing market rules and technical standards as they apply to energy storage resources. Further information on energy storage can be found in the AESO s Energy Storage Initiative Issue Identification paper. 54 As energy storage technologies develop, the overall potential will be related to market dynamics with two drivers for the application. First, storage technologies are well suited to receive energy during times of surplus and to release energy during times of energy scarcity. This serves well as a time-shifting function within the market to decrease price volatility while capturing arbitrage opportunities. The second driver for storage is related to the firming of variable generation. Geothermal As a renewable energy source that can generate baseload electricity, geothermal technology extracts heat from the earth s inner layers to produce electricity. In most cases, this is accomplished by pumping fluids from several thousand feet below the earth s surface to an electrical generation facility. Geothermal energy is considered a renewable energy source because when managed efficiently, a site will provide a long-term supply of heat which does not burn fossil fuel. Early estimates limit the future geothermal generation in Alberta to 300 to 500 MW. 55 In addition, there are opportunities for residential and commercial heating and cooling systems. Geothermal provides baseload electricity, and development would be in response to that requirement. Given high estimated capital costs, and the low overall potential in Alberta, geothermal is not expected to provide significant generation capacity to the system. Nuclear Nuclear power generation is a type of thermal power in which electricity is generated from steam produced by the fissioning, or splitting, of uranium atoms. These power plants range in size from smaller 10 MW designs to larger 1,200 MW designs. Currently there are international efforts to develop micro-scale nuclear generation units that are self-contained and require minimal operational oversight. In 2013, there were reports that Toshiba had plans to develop a 10 MW 4S nuclear reactor to be used in the oilsands. The reactor would create steam for use in an in situ operation and would not need to be refueled for up to 30 years. The reactor design still needs to obtain regulatory approval before any development could proceed. While Alberta has no nuclear generation, in 2008 Bruce Power had applied for a license to build a nuclear power plant but abandoned the project in 2011. During that time the Alberta 54 http://www.aeso.ca/downloads/formatted_es_is_paper_final_20130613.pdf 55 Borealis GeoPower. CanGea 3rd Geothermal Power Forum, November 4, 2011 PAGE 60 Appendix C: Forecast Considerations

government conducted consultations with Albertans 56 to identify the opinions held on nuclear energy. One key finding was that the majority of Albertans preferred that nuclear power plants be considered on a case-by-case basis. The potential for the development of nuclear reactors will depend on the ability of reactors to obtain regulatory approvals, public perception, and the ability to secure a role within industrial operations and the market. Given the withdrawal of the 2008 Bruce Power project and the required regulatory approvals for small nuclear, nuclear projects are not expected to develop within Alberta at this time. Levelized Unit Electricity Costs The relative cost of different generation technologies is considered in developing the generation forecast. This section estimates the comparative cost of several commercial generation technologies. The Levelized Unit Electricity Cost (LUEC) is used to calculate the break-even cost of electricity over the lifetime of a project; it is not, however, an indication of profitability. While the LUEC is a summary measure of the overall competitiveness of different generating technologies, actual plant investment decisions are affected by the specific technological and regional characteristic of a project, which involve numerous other priced and unpriced considerations. The comparative cost is represented by the LUEC, which is the constant electricity price required to cover all costs, including a specified rate of return, over the entire life of the project. The LUEC is derived using a discounted cashflow approach, which sets the present worth of revenue equal to the present worth of expenses, determining the constant price required to cover all expenses. The costs included in the calculation are capital, operating and maintenance (O&M), fuel, emission and taxes, and excludes transmission-related charges. The assumptions used in the LUEC are based on publicly available information but are Alberta-specific. These assumptions are benchmarked for validity against other external estimates, estimates for existing Alberta-based projects, and stakeholder input. In addition, sensitivities were created around the assumptions to test the impact on the overall comparative cost ranking. 56 http://www.energy.alberta.ca/electricity/pdfs/albertanuclearconsultationfull.pdf Appendix C: Forecast Considerations PAGE 61

Technology Considerations For the 2014 LTO, the LUEC was calculated for the following technologies: Renewables Wind Photovoltaic Solar Hydro-electricity Gas-fired Simple-cycle Combined-cycle Cogeneration Coal-fired Coal Generation with Carbon Capture and Storage (CCS) Key inputs into the calculation of the LUEC include operating characteristics and costs for each technology. Operating characteristics include net capacity, operating heat rate, average annual capacity factor, CO2 emission intensity, and project life. Cost assumptions include overnight 57 capital costs, construction time, fuel prices, fixed and variable operating and maintenance costs, tax rates, and CO2 emission prices or revenues (if applicable). The assumptions used in the LUEC are representative only of the various technologies as their value can vary because of geography, application, site specifics, as well as change as technologies evolve. All inputs are assumed for generic utility-scale plants. The costs may not necessarily match those derived in other studies that employ different approaches or definitions to cost estimation. The estimate for hydro generation is a high-level generic estimate for a medium-sized reservoir facility; cost to develop an actual facility may differ due to site-specific factors. LUEC Results The relative ranking of the costs of different generation technologies can be seen in Figure C-2. The costs of coal-fired generation are noticeably higher than for other technologies due to the cost of installing and operating CCS systems. While CCS significantly lowers the net emission intensity for coal-fired generation, it also requires roughly one-third of gross capacity output in auxiliary load, which adds to the overall cost of the facility. CCS is a new technology which is still in the development stage, and so there is a great deal of uncertainty regarding the impact on the LUEC. However, given current cost estimates, coal-fired generation with CCS is not likely to be developed in Alberta without significant capital subsidies, very high carbon costs, or both. 57 Interest incurred during construction is not included PAGE 62 Appendix C: Forecast Considerations

(2013 $Cdn/MWh) AESO 2014 Long-term Outlook Figure C-2: Comparative Generation Cost $300 $250 $237 $200 $150 $176 $100 $82 $89 $105 $106 $69 $110 $50 $0 Wind Hydro Cogeneration Combinedcycle Simplecycle PV Solar Coal w/ CCS The LUEC confirms the current preference to develop gas-fired generation plants, as the lowest cost technology is for combined-cycle, followed by wind. The two other gas-fired technologies then follow in relative ranking with hydro. 58 Note that the cost for the generic hydro facility above is not site-specific and so may vary significantly from an actualized project in Alberta. Sensitivities Sensitivities for the levelized generation costs were analyzed around the following key drivers: capital cost, capacity factor, fuel prices 59 (if applicable), and CO2 emission prices. These sensitivities were used to test boundary conditions which would alter the relative ranking of generation costs. Sensitivities were also used to develop the scenarios in Section 7. The impact of the sensitivity varied by type of technology. For example, rising fuel prices had no effect on renewable technologies but a significant impact on combined-cycle generation. In general, the larger the cost of construction, the smaller the impact of other drivers. Scenarios The levelized unit electricity costs were adjusted for the Environmental Shift and Energy Transformation Scenarios to reflect the different conditions from the main outlook. The assumptions used for scenarios are summarized in the table below. All scenarios incorporate the Alberta Specified Gas Emitters Regulation (SGER) framework, but the Environmental Shift and Energy Transformation Scenarios utilize more restrictive parameters. 58 Cogeneration is treated as a stand-alone facility and is net fuel allocated to steam 59 Natural gas prices for the main outlook are discussed in Section 3.3.1 and additional details are included in the 2014 LTO data file. Appendix C: Forecast Considerations PAGE 63

Table C-5: LUEC Environmental Assumptions 60 SGER Main Outlook and Low Growth* Environmental Shift Energy Transformation Annual Reduction 2% 5% 10% Reduction Ceiling 12% 50% None CO2 Price 2013 $15 $25 $25 CO2 Price 2020 $15 $55 $55 CCS Production Subsidy 61 No No Yes Technology Breakthrough No No Solar, CCS Thermal Fuel Prices Reference Reference High * Based on existing policy Source: AESO Compared to the main outlook, renewable technologies in the Environmental Shift Scenario become more cost competitive relative to thermal technologies due to stronger revenues from increased CO2 prices. In the Energy Transformation Scenario, the use of fossil fuels is restricted due to strong global environmental concerns. These concerns result in higher natural gas prices which increase the cost of thermal generation. There is also research and development support for emerging low-emission generating technologies such as solar and CCS. CCS is further advantaged by a production subsidy, and natural gas and coal prices increase due to environmental regulations. Cumulatively, these changes raise the costs of thermal generation relative to other low-emitting technologies. The LUEC for generation technologies in the main outlook and the environmental scenarios is summarized in Figure C-3. 60 2013 $Cdn 20/MWh for 20 years PAGE 64 Appendix C: Forecast Considerations

Combined Cycle Wind Hydro Cogen Simple Cycle Solar Coal w/ CCS Combined Cycle Wind Hydro Cogen Simple Cycle Solar Coal w/ CCS Combined Cycle Wind Hydro Cogen Simple Cycle Solar Coal w/ CCS (2013 $Cdn/MWh) AESO 2014 Long-term Outlook Conclusion The levelized cost is an important input into the generation forecast for the 2014 LTO and is one of many factors considered. The results show that given current cost inputs, combined-cycle generation is the lowest cost generation technology followed by wind. This is consistent with current projects that have applied to the AESO for connection in that there are large amounts of both of these technologies. Baseload technologies such as hydro and coal with CCS are higher cost as both have large up-front capital costs. Even if considerable reductions in capital costs were to occur, coal-fired generation with carbon capture is a high-cost baseload technology and would not be as competitive as other technologies. Solar has been assessed as a higher-cost technology, but if reductions in capital costs occur and if the cost of other generation sources increase from either fuel input costs or emission-related costs, solar could be competitive. The costs of simple-cycle reflect its operational output style of peak load operation and low capacity factors. Cogeneration costs are primarily related to the cost of power output. The AESO s cogeneration LUEC assumes economic benefits from natural gas efficiencies compared to standalone boilers and generation sources as well as from SGER. However, additional economic benefit is derived from the value of heat and steam or from operational efficiencies such as shared operation and maintenance costs are not included in the AESO s cogeneration LUEC. Figure C-3: LUEC Scenario Comparison $300 $250 $200 $150 $100 $50 $0 Main Outlook and Low Growth Environmental Shift Energy Transformation Source: AESO Appendix C: Forecast Considerations PAGE 65

Appendix D Forecast Comparison As part of its forecasting process, the AESO assesses past forecasts along with Alberta s actual demand and electricity usage to verify methodology and identify variances that could impact the current energy and load forecast. Furthermore, since the 2014 LTO is intended to be used as a key input into transmission planning, the AESO also identifies any material changes between forecasts so that impacts to current and future transmission plans can be addressed. Table D-1: Historical Forecast Accuracy Comparison of AIL Energy Forecast and Actual Year of Forecast FC 2009 2012 LTO 2012 LTOU GWh % GWh % GWh % 1st Year of Forecast 271 0.4% 591 0.8% 582 0.8% 2nd Year of Forecast 735 1.0% 1,057 1.4% 1,124 1.5% 3rd Year of Forecast 1,712 2.3% 1,987 2.6% 4th Year of Forecast 3,389 4.5% 5th Year of Forecast 5,427 7.0% Comparison of Peak Load Forecast and Actual Year of Forecast FC 2009 2012 LTO 2012 LTOU MW % MW % MW % 1st Year of Forecast -390-3.8% -41-0.4% 316 3.0% 2nd Year of Forecast -26-0.3% 242 2.3% 180 1.6% 3rd Year of Forecast -32-0.3% 174 1.6% 4th Year of Forecast 477 4.5% 5th Year of Forecast 525 4.7% Note: Positive numbers indicate the forecast values exceeded actuals. Negative values indicate actuals exceeded what was forecast. PAGE 66 Appendix D: Forecast Comparison

Regional Comparison of Forecasts As can be seen in Table D-2, the 2012 LTOU showed a marked increase over the 2012 LTO in the Northeast and Northwest Regions. As was noted in the 2012 LTOU, many oilsands projects advanced through their regulatory and development processes which increased the oilsands forecast. Furthermore, the 2012 LTOU was slightly higher than the 2012 LTO in later years (2028-2032) due to a higher oilsands forecast. From the 2012 LTOU to the 2014 LTO, there were minimal differences overall. The relatively minor differences between the 2012 LTOU and the 2014 LTO are primarily caused by changes in projects (projects added and removed as well as timing changes). Overall, the fundamentals driving the 2014 LTO are highly consistent with those of the 2012 LTOU. Table D-2: Comparison of Regional Forecasts (MW) 2019 Northwest Northeast Edmonton Central South Losses AIL 2012 LTO 1,109 4,118 2,596 1,888 3,687 380 13,778 2012 LTOU 1,337 4,527 2,466 1,963 3,604 417 14,314 2014 LTO 1,317 4,613 2,500 1,951 3,464 429 14,274 2024 Northwest Northeast Edmonton Central South Losses AIL 2012 LTO 1,232 4,669 2,844 2,073 4,083 423 15,325 2012 LTOU 1,408 5,465 2,580 2,039 3,843 460 15,795 2014 LTO 1,443 5,265 2,785 2,152 3,887 482 16,014 2032* Northwest Northeast Edmonton Central South Losses AIL 2012 LTO 1,377 5,254 3,212 2,283 4,678 477 17,281 2012 LTOU 1,625 6,154 3,004 2,337 4,545 530 18,194 2014 LTO 1,600 5,770 3,246 2,416 4,525 545 18,102 * 2032 values compared because 2012 LTO and 2012 LTOU did not forecast to 2034 Appendix D: Forecast Comparison PAGE 67

Appendix E System Load Table E-1: System Load Energy (GWh)** Year Total AIL Total On-site Generation Energy BTF Energy (Energy served by On-site Generation) System Load Energy [A] [A] [A] - [B] 2012* 75,574 15,918 59,656 2013* 77,451 16,980 60,471 2014 79,310 27,508 17,387 61,780 2015 82,214 28,078 18,024 63,918 2016 85,716 29,326 18,793 66,404 2017 90,669 32,567 19,877 69,940 2018 95,646 36,743 20,969 73,883 2019 100,106 37,124 21,947 77,214 2020 104,344 38,162 23,495 79,447 2021 107,267 38,961 24,264 81,601 2022 109,514 40,541 25,108 83,004 2023 111,898 41,546 25,518 84,977 2024 114,249 41,907 25,696 87,150 2025 116,234 25,895 88,936 2026 118,391 26,096 90,892 2027 120,303 26,298 92,603 2028 122,158 26,502 94,254 2029 123,737 26,707 95,628 2030 125,508 26,914 97,191 2031 127,124 27,123 98,599 2032 128,734 27,333 99,999 2033 129,997 27,545 101,050 2034 131,351 27,758 102,191 * Denotes actuals ** Table data corrected June 2014 PAGE 68 Appendix E: System Load

Table E-2: System Load at AIL Peak (MW)** Year Total AIL Peak Load Total On-Site Generation BTF (Load served by On-site Generation) System Load at AIL Peak 2012* 10,599 2,026 8,574 2013* 11,139 2,176 8,963 2014 11,323 3,677 2,257 9,066 2015 11,811 3,339 2,310 9,501 2016 12,531 4,031 2,479 10,052 2017 13,192 4,744 2,552 10,640 2018 13,783 4,940 2,735 11,048 2019 14,274 4,950 2,906 11,368 2020 14,722 4,966 3,041 11,681 2021 15,033 5,262 3,114 11,920 2022 15,376 5,195 3,000 12,376 2023 15,672 5,579 3,212 12,460 2024 16,014 5,459 3,437 12,578 2025 16,318 3,463 12,854 2026 16,643 3,490 13,153 2027 16,869 3,517 13,352 2028 17,137 3,545 13,592 2029 17,403 3,572 13,831 2030 17,647 3,600 14,048 2031 17,870 3,628 14,243 2032 18,102 3,656 14,446 2033 18,308 3,684 14,624 2034 18,519 3,713 14,807 * Denotes actuals ** Table data corrected June 2014 Appendix E: System Load PAGE 69

Table E-3: Demand Transmission Service (DTS) Energy (GWh) Year 2014 LTO 2012* 55,736 2013* 56,959 2014 58,162 2015 60,328 2016 62,949 2017 66,665 2018 70,389 2019 73,779 2020 76,399 2021 78,496 2022 79,838 2023 81,755 2024 83,865 2025 85,601 2026 87,498 2027 89,154 2028 90,744 2029 92,179 2030 93,683 2031 95,031 2032 96,369 2033 97,358 2034 98,321 * Denotes actuals PAGE 70 Appendix E: System Load

Appendix F Industry Engagement As part of developing the 2014 Long-term Outlook, the AESO held individual meetings with a large number of market participants and other interested parties from May to October 2013. These meetings focused on gathering information for the forecast, such as project details, corporate forecasts, market outlooks and general expectations for future load and generation in Alberta. In preparing the 2014 LTO, the AESO met with many organizations including those listed below. The AESO is grateful for the guidance, input and comments from the individuals representing these companies. Their guidance is not in any way an endorsement of the accuracy or validity of the 2014 LTO. Alberta-Pacific Forest Industries ATCO Power BluEarth Renewables Bull Frog Power Canadian Association of Petroleum Producers Canadian Natural Resources Limited Capital Power Corporation Canadian Wind Energy Association Cenovus Energy Inc. ConocoPhillips Enbridge Inc. Enbridge Pipelines ENMAX Corporation Energy Resources Conservation Board Husky Energy Howell-Mayhew Engineering Imperial Oil Kinder Morgan Maxim Power Corp. MEG Energy NaturEner Energy Canada Inc. Nexen Inc. Pembina Institute PIRA Energy Group SkyFire Energy Statoil Canada Ltd. Shell Canada Energy Suncor Energy Syncrude Canada Ltd. TAMA Power TransAlta Corporation TransCanada Total E&P Canada West Fraser Pulp In co-operation with the AESO, the TFOs and DFOs have provided updated forecasts for each of their facilities and these have been incorporated into the 2014 LTO. ATCO Electric City of Lethbridge City of Medicine Hat City of Red Deer EPCOR Utilities Inc. ENMAX Power Corporation FortisAlberta Inc. Appendix F: Industry Engagement PAGE 71

Appendix G Alberta Reliability Standard Requirements The AESO has undertaken an initiative to adopt the applicable North American Electric Reliability Council (NERC) reliability standards as Alberta Reliability Standards. In January 2010, four standards were approved relating to Modeling, Data and Analysis (MOD) and load forecasting. The four standards relating to documentation and reporting requirements are listed in Table G-1. Table G-1: Reliability Requirements: Documentation and Reporting Standards Standard MOD-016-AB-1.1 MOD-017-AB-0.1 MOD-018-AB-0 MOD-019-AB-0 Description Documentation of Data Reporting Requirements for Actual and Forecast Demands, and Net Energy for Load Aggregated Actual and Forecast Demands and Net Energy for Load Reports of Actual and Forecast Demand Data Forecasts of Interruptible Demands Data More information regarding Alberta Reliability Standards can be found on the AESO website. 61 Under MOD-016-AB-1.1, 62 the AESO must have documentation identifying the scope and details of the actual and forecast demand data and net energy for load data to be reported for system modeling and reliability analyses. This 2014 LTO publication is that documentation. In accordance with MOD-016-AB-1.1, the 2014 LTO is published and distributed within 30 calendar days of a revision being approved by the AESO. Under MOD-017-AB-0.1, the AESO is required to report to WECC monthly and annual hourly peak demand and energy for the prior year as well as forecast for the next 10 years. Under MOD-019-AB-0, the AESO must also provide to WECC its forecast of interruptible demand data. This data is included in the 2014 LTO data file. Under MOD-018-AB-0, the AESO must indicate whether the demand data of other balancing authorities is included. For the purposes of this document, the load of other balancing authorities is not included in any of the values or figures shown. That MOD also requires that the AESO address how it treats uncertainties in the forecast. The AESO uses scenarios to deal with uncertainties as described in Section 7. 61 http://www.aeso.ca/rulesandprocedures/17004.html 62 http://www.aeso.ca/downloads/mod-016-ab-1.1.pdf PAGE 72 Appendix G: Alberta Reliability Standard Requirements

Load Forecast Reporting to Western Electricity Coordinating Council (WECC) For compliance to the related standards as described above as well as reporting requirements to the Western Electricity Coordinating Council (WECC), AESO load forecasts are described in the following terms: A. Alberta Internal Load (AIL) B. Behind-the-Fence (BTF) is classified as Non-reserved Demand C. Demand Opportunity Service and Load Shed Service Imports (LSSi) are classified as Non-firm Demand D. Load that is not classified as either non-reserved or non-firm is classified as: Firm Peak Demand such that [A] = [B] + [C] + [D] A ALBERTA INTERNAL LOAD (AIL) B NON-RESERVE DEMAND (e.g. BTF DEMAND) C NON-FIRM DEMAND (e.g. DOS, LSSi) D FIRM PEAK DEMAND Appendix G: Alberta Reliability Standard Requirements PAGE 73

Appendix H Glossary of Terms Alberta Interconnected Electric System (AIES): the system of interconnected transmission power lines and generators. Alberta internal load (AIL): total provincial electricity consumption including behind-the-fence, the City of Medicine Hat, and losses (transmission and distribution). Alberta Utilities Commission (AUC): regulates the utilities sector as well as natural gas and electricity markets to protect the social, economic and environmental interests of Alberta. Annual Energy Outlook (AEO): the annual forecast by the U.S. Energy Information Administration, a sub-department of the U.S. Department of Energy. Baseload: the minimum amount of electric power delivered or required over a given period of time at a constant rate. Bulk transmission system: the integrated system of transmission lines and substations that delivers electric power from major generating stations to load centers. The bulk system, which generally includes the 240 kv and 500 kv transmission lines and substations, also delivers/ receives power to and from adjacent power systems. Behind-the-fence load (BTF): industrial load characterized by being served in whole, or in part, by on-site generation. Bitumen: sand and rock that contain a heavy, viscous form of crude oil, particularly in relation to the Alberta oilsands. Carbon capture and storage (CCS): technology employed to prevent the release of large quantities of carbon dioxide (CO2) into the atmosphere from fossil fuel use in power generation and other industries by capturing CO2, transporting it and ultimately, pumping it into underground geologic formations to securely store it. Cogeneration: the simultaneous production of electricity and another form of useful thermal energy used for industrial, commercial, heating or cooling purposes. Combined-cycle generation: a system in which a gas turbine generates electricity and the waste heat is utilized to create steam that generates additional electricity using a steam turbine. Comprehensive Regional Infrastructure Sustainability Plan (CRISP): the Government of Alberta s long-term approach to planning infrastructure in Alberta s three oilsands geographic areas. Customer sectors: used to classify types of load. For the purposes of the 2014 LTO, five sectors were used: Industrial (without Oilsands), Oilsands, Commercial, Residential, and Farm. Demand side management (DSM): generally refers to activities occurring on the demand side of the meter that are implemented by the customer directly or by load serving entities. Distribution facility owner (DFO): term used to describe an electric distribution system wire owner. PAGE 74 Appendix H: Glossary of Terms

Effective generation capacity: generation capacity available to serve peak demand, taking into consideration a reduction in capacity from variable supply sources such as wind and hydro. Energy Information Administration (EIA): a sub-department of the U.S. Department of Energy. This agency collects, analyzes, and disseminates independent and impartial energy information to promote sound policymaking, efficient markets, and public understanding of energy and its interaction with the economy and the environment. Energy: electricity consumption over a given period of time for a defined geographic area expressed in units kwh (kilowatt hour), MWh (megawatt hour) or GWh (gigawatt hour). Capacity: amount of electric power installed or required from a generator, turbine, transformer, transmission circuit, substation or system, as rated by the manufacturer. Gigajoules: a unit of energy equal to one billion joules. As a point of reference, Alberta Energy estimates that a typical Canadian home uses about 120 gigajoules worth of natural gas each year. Gigawatt hour (GWh): one billion watt hours. Greenhouse gas (GHG): gases in the earth s atmosphere that absorb and emit radiation within the thermal infrared range (the greenhouse effect ). Greenhouse gases include water vapour, carbon dioxide, methane, nitrous oxide, and ozone. Gross domestic product (GDP): one of the measures of income and output for a given economy. GDP is defined as the total market value of all final goods and services produced within the economy in a given period of time (usually a calendar year). Independent System Operator (ISO): an organization established to plan, coordinate, control and monitor the operation of a bulk transmission system. The ISO in Alberta is defined by Section 7 of the Electric Utilities Act. In situ: various methods, including steam injection, solvent injection, and firefloods, used to recover deeply buried bitumen deposits. Levelized Unit Electricity Cost (LUEC): the constant electricity price required to cover all costs, including a specified rate of return, over the entire life of the generation project. Load (or demand): the rate at which electric energy is delivered to or by a system or part of a system, generally expressed in kilowatts or megawatts, at a given instant or averaged over any designated interval of time. It can also be the rate at which electric energy is being used by a demand customer. Load factor: ratio of average power demand (load) to peak load during a specified period of time, often expressed as a per cent. Megawatt (MW): one million watts. Micro-generation: In Alberta, under the Micro-generation Regulation, generators that are connected to the grid who produce one megawatt or less and are powered by renewable energy with greenhouse gas emissions that cannot exceed 418 KG per megawatt hour. Appendix H: Glossary of Terms PAGE 75

Needs Identification Document: a document filed by the AESO with the Alberta Utilities Commission to define the need to reinforce the transmission system to meet load growth and/or provide non-discriminatory access to interconnect new loads and generators to the system. Peak load/demand: the maximum amount of power demand (load) registered in a defined period of time. The value may be the maximum instantaneous load or, more usually, the average load over a designated interval of time such as one hour, normally stated in kilowatts or megawatts. Point-of-delivery (Pod): the point at which electricity is transferred from transmission facilities to facilities owned by a market participant receiving system access service under the ISO tariff, including an electric distribution system. Price-responsive load: large commercial and industrial customers with flexible operations that enable them to reduce load or demand in response to market price signals. Provincial Energy Strategy (PES): the Government of Alberta s long-term action plan for Alberta to achieve its goals of clean energy production, wise energy use and sustained economic prosperity. Simple-cycle generation: where a gas turbine is the prime mover in a plant. Liquid or gaseous fuel is burned and passed to a turbine where the hot gasses expand, driving the turbine that, in turn, drives a generator. Steam assisted gravity drainage (SAGD): an oil extraction method used in an oilsand deposit utilizing horizontal well bores in the oil-bearing layer together with pairs of parallel bores drilled to form a grid. Steam is forced into the oil-bearing layer through the upper well bore which lowers the viscosity of the oil, enabling it to flow into the lower well bore to be pumped to the surface. Substation/switching station: a facility where equipment is used to tie together two or more electric circuits through switches (circuit breakers). The switches are selectively arranged to permit a circuit to be disconnected or to change the electric connection between the circuits. Supercritical Pulverized coal (SCPC): a pulverized coal power plant which operates above the critical point of water (647.096 K and 22.064 MPa). As the operating pressures and temperatures increase for a coal plant, so does the operating efficiency. System Load: the total, in an hour, of all metered demands under Rate DTS, Rate FTS and Rate DOS of the ISO tariff plus transmission system losses. Transmission losses: energy that is lost to the atmosphere in the form of heat through the process of transmitting electrical energy. Transmission system (electric): an interconnected group of electric transmission lines and associated equipment for moving or transferring electric energy in bulk between points of supply and points at which it is delivered over the distribution system lines to consumers, or is delivered to other electric systems. Unconventional natural gas: unlike conventional or free natural gas that is typically trapped within multiple, relatively small, porous zones in naturally occurring rock formations, unconventional natural gas comes from unconventional formations and is more difficult to recover. Reservoirs include tight gas, coal bed methane, gas hydrates, and shale gas. Recent technological breakthroughs have made this type of gas easier to recover than it once was. Upgrading: the process of converting heavy oil or bitumen into synthetic crude oil. PAGE 76 Appendix H: Glossary of Terms

This document complements the AESO s existing publications and supports our commitment to sharing information with market participants, other stakeholders and all Albertans in a timely, open and transparent manner. Readers are invited to provide comments or suggestions for future reports. For more information or to give us your feedback, contact forecast@aeso.ca

Alberta Electric System Operator 2500, 330-5th Avenue SW Calgary, Alberta T2P 0L4 Phone: 403-539-2450 Fax: 403-539-2949 www.aeso.ca www.poweringalberta.com REV 0614