aeso 2014 long-term outlook

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

0 Executive Summary


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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.



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.



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.

2.0 Introduction


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.

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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


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 Trends2 www.aeso.ca > Customer Connections > Connection Queue

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.

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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 long-

term 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.


0 Economic Outlook


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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



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

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

$20,000$0 $40,000 $60,000 $80,000($Cdn Millions)

$100,000 $120,000

Figure 1: Inventory of Major Projects in Alberta

Source: Alberta Enterprise and Advanced Education (Feb. 2014)

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.

4.0 Environmental Drivers

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.

3 http://www.gazette.gc.ca/rp-pr/p2/2012/2012-09-12/html/sor-dors167-eng.html

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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 combined-

cycle 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 contributions5 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.html5 Currently $15/tonne for every tonne exceeding the allocated limit6 http://ccemc.ca/7 http://carbonoffsetsolutions.climatechangecentral.com/policy-amp-regulation/alberta-offset-system-compliance-a-

glance/2012-compliance-year

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.

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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.



5.3 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.

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

Total 14,568 MW

Existing as of December 31, 2013Total Capacity: 14,568

AIL Peak: 11,139

30% Coal 5,402


14% Combined-cycle 2,513

7% Simple-cycle 1,228

5% Hydro 894

10% Wind 1,751

3% Other 468

Total 18,259 MW

2019Total Capacity: 18,259

AIL Peak: 14,274

26% Coal 5,402




4% Hydro 894

11% Wind 2,263

2% Other 498

Total 21,039 MW


AIL Peak: 16,014

10% Coal 2,509




4% Hydro 894

11% Wind 2,679

3% Other 864

Total 24,953 MW


AIL Peak: 18,519

2014 LTO: Generation Capacity Mix Comparison

Source: AESO

0 Regional Outlooks


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

17Rainbow Lake

49Stavely 52

Vauxhall

4Medicine Hat

53Fort MacLeod

55Greenwood

54Lethbridge

32Wainwright

36 Alliance/Battle River

37Provost35

Red Deer34Abraham Lake

30Drayton Valley

29Hinton / Edson

31Wetaskiwin

38Caroline

39Didsbury

42Hanna

57 Airdrie44

Seebee 6Calgary 45

Strathmore/Blackie

47Brooks

48Empress

18High Level

25Fort McMurray

19Peace River

20Grande Prairie

22Grande Cache

23Valley View

21 High Prairie

26SwanHills24

Fox Creek

27Athabasca /Lac La Biche

28Cold Lake

40Wabamun

60Edmonton

33Fort

Sask. 56Vegreville

13Lloydminster

46High River

43Sheerness

AESO Planning Regions* Central

Edmonton

Northeast

Northwest

South

* Planned areas are numbered

Source: AESO



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

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 simple-

cycle 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



6.3 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 Summer Peak (MW) 883

2013/2014 Winter Peak (MW) 1,111


Area (000 km2) 230


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.

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.



Table 6.3.2–1: Northwest Load and Generation Capacity Forecast


Load at AIL Peak 1,111 1,443 1,628

Coal-fired 144 0 0

Cogeneration 191 881 881

Combined-cycle 73 73 773


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



2013/2014 Winter Peak (MW) 2,158

Population (000s) 1,234

Area (000 km2) 22


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).

0 Regional Outlooks


6.4.2 Generation

The Edmonton Region contains primarily coal-fired generation with the potential for gas-

fired 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


Load at AIL Peak 2,158 2,785 3,340

Coal-fired 4,658 4,082 1,729


Combined-cycle 0 900 3,300


Hydro 0 0 0

Wind 0 0 0

Other 0 0 158



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



2013/2014 Winter Peak (MW) 1,608


Area (000 km2) 131


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

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 combined-

cycle 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


Load at AIL Peak 1,608 2,152 2,466

Coal-fired 689 540 0


Combined-cycle 0 0 500


Hydro 485 485 485

Wind 232 439 505

Other 61 76 84



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



2013/2014 Winter Peak (MW) 3,041

Population (000s) 1,691

Area (000 km2) 95


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.

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 transmission-

connected 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


Load at AIL Peak 3,041 3,887 4,674

Coal-fired 780 780 780


Combined-cycle 770 2,088 2,088


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.



Figure 6.7–1: Regional Load Forecast Summary

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

AESO Planning Regions

Central

Edmonton

Northeast

Northwest

South

0

2,000

4,000

6,000

8,000

2003

2008

2013

2019

2024

2034

Northeast

0

2,000

4,000

6,000

2003

2008

2013

2019

2024

2034

8,000Northwest

0

2,000

4,000

6,000

8,000

2003

2008

2013

2019

2024

2034

Edmonton

0

2,000

4,000

6,000

8,000

2003

2008

2013

2019

2024

2034

Central

0

2,000

4,000

6,000

8,000

2003

2008

2013

2019

2024

2034

South

NW

Central

South

NE

Edm

( MW

)

( MW

)( M

W)

( MW

)

( MW

)

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.

7.0 Scenarios

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.

Sto

ck p

hoto

grap

h.


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 command-

and-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


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

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


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, large-

scale 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.

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


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, combined-

cycle 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 coal-

fired 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.

0 Scenarios


Table 7.6–1: 2014 LTO Load and Generation Comparison (MW)

2019 Main Outlook Low GrowthEnvironmental

ShiftEnergy

Transformation

Demand AIL Peak 14,274 12,000 13,380 11,777

Generation Capacity

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

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


ShiftEnergy

Transformation

Demand AIL Peak 16,014 12,689 15,288 12,470

Generation Capacity

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

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


ShiftEnergy

Transformation

Demand AIL Peak 18,519 13,504 18,804 13,568

Generation Capacity

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

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

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 8,5782005* 33,973 6,695 7,769 12,081 1,705 62,223 3,869 176 66,268 9,580 8,5662006* 34,042 8,347 8,254 12,733 1,769 65,144 4,048 178 69,371 9,661 9,0502007* 32,973 8,576 8,539 13,114 1,806 65,007 4,485 167 69,660 9,710 9,3212008* 31,998 9,431 8,833 13,526 1,803 65,592 4,138 217 69,947 9,806 9,5412009* 30,950 10,660 9,090 13,534 1,900 66,135 3,595 184 69,913 10,236 9,1172010* 31,525 11,134 9,071 13,748 1,708 67,186 4,342 196 71,723 10,226 9,3432011* 31,631 11,917 9,333 14,207 1,828 68,916 4,529 155 73,600 10,609 9,5522012* 32,768 13,364 9,412 14,596 1,800 71,941 3,432 201 75,574 10,599 9,8852013* 33,065 14,341 9,678 14,778 1,836 73,699 3,556 202 77,457 11,139 10,0632014 33,200 15,097 9,959 15,253 1,839 75,349 3,716 245 79,310 11,323 10,4212015 33,724 16,774 10,153 15,609 1,846 78,106 3,862 245 82,214 11,811 10,7652016 34,182 19,122 10,343 15,932 1,853 81,432 4,039 245 85,716 12,531 11,1702017 35,282 22,241 10,527 16,225 1,861 86,136 4,289 245 90,669 13,192 11,7992018 36,727 24,950 10,708 16,608 1,869 90,862 4,540 244 95,646 13,783 12,3902019 38,007 27,334 10,889 16,990 1,877 95,097 4,765 245 100,106 14,274 12,9382020 39,124 29,631 11,068 17,411 1,885 99,119 4,979 246 104,344 14,722 13,4292021 39,842 31,117 11,244 17,800 1,894 101,896 5,126 244 107,267 15,033 13,8652022 40,509 32,009 11,416 18,194 1,902 104,031 5,239 244 109,514 15,376 14,1482023 41,478 32,711 11,586 18,609 1,910 106,294 5,360 244 111,898 15,672 14,4602024 42,437 33,386 11,754 19,031 1,919 108,526 5,478 244 114,249 16,014 14,7312025 43,370 33,734 11,925 19,455 1,927 110,411 5,578 244 116,234 16,318 15,0482026 44,307 34,260 12,089 19,865 1,937 112,458 5,687 245 118,390 16,643 15,3272027 45,152 34,637 12,252 20,289 1,945 114,275 5,783 244 120,303 16,869 15,6272028 45,940 35,008 12,413 20,720 1,955 116,036 5,877 245 122,158 17,137 15,8172029 46,663 35,183 12,575 21,151 1,964 117,536 5,957 244 123,737 17,403 16,0832030 47,481 35,428 12,737 21,597 1,974 119,217 6,046 245 125,508 17,647 16,3292031 48,208 35,611 12,900 22,049 1,983 120,751 6,128 245 127,124 17,870 16,5542032 48,915 35,807 13,062 22,503 1,993 122,281 6,209 245 128,734 18,102 16,7602033 49,392 35,913 13,224 22,948 2,003 123,481 6,272 244 129,997 18,308 16,9752034 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.

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


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


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

Appendix B Forecasting Process

Historical consumption data

ENERGY FORECAST (annual consumption forecast

by customer sector)

Historical load by POD

Distribution Facility Owner (DFO) forecasts

Project specific information

LOAD FORECAST (hourly load data

by POD)

Generation resource assessments

Levelized unit electricity cost

Project specific information

GENERATION FORECAST(annual capacity addition

by resource type)

SYSTEM LOADFORECAST

Third-party economic forecast

� Economic forecast from third-party experts cross-referenced with other economic forecasts to confirm reasonableness and consistency.

� Energy forecasts by customer sector to reflect sector-specific drivers and relationships.

� 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.

ECONOMIC FORECAST AND ASSUMPTIONS

Inputs Products Additional Information

On-site generation forecast combined with load

forecast to create the system load forecast.

� 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.

STA

KE

HO

LD

ER

CO

NS

ULT

AT

ION

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


Table C-1: Forecast Considerations

Environmental Drivers Energy and Load Generation

�� Oilsands Development

�� Climate Change�− Federal policies�− Provincial policies

�� Customer Sector Energy

�� Demand Side Management�− Energy efficiency�− Demand response

�� Oilsands�− Alternative extraction

technologies�− Electric intensities and

efficiencies�− Upgrading capacity

�� Export Pipelines

�� Current Generation Technologies�− Coal�− 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.asp10 http://www.energy.alberta.ca/Initiatives/3082.asp



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-A546-8CCF09010A2312 http://www.gazette.gc.ca/rp-pr/p2/2012/2012-09-12/html/sor-dors167-eng.html13 http://www.ec.gc.ca/default.asp?lang=En&n=714D9AAE-1&news=4D34AE9B-1768-415D-A546-8CCF09010A23



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 program14 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 million18 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/1414515 http://www.nrcan.gc.ca/ecoaction/644416 CCA 43.1 & 43.2; CRCE; SR&ED and ITCs17 http://www.climatechange.gc.ca/default.asp?lang=En&n=72F16A84-118 http://www.climatechange.gc.ca/default.asp?lang=En&n=72F16A84-1



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 ozone19 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.pdf20 http://www.ccme.ca/assets/pdf/cams_proposed_framework_e.pdf for proposed levels



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 Strategy23 in 2012, which links with Alberta’s established Comprehensive Air Quality

Management System24 (CAMS), the decision making process established by the provincial

Clean Air Strategic Alliance (CASA).

21 http://oee.nrcan.gc.ca/regulations/1772422 http://environment.gov.ab.ca/info/library/7894.pdf23 http://environment.gov.ab.ca/info/library/8692.pdf24 http://casahome.org/DesktopModules/Bring2mind/DMX/Download.aspx?Command=Core_Download&EntryId=898&PortalI

d=0&TabId=78



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



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 Fund27—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.html27 http://ccemc.ca/28 http://carbonoffsetsolutions.climatechangecentral.com/policy-amp-regulation/alberta-offset-system-compliance-a-

glance/2012-compliance-year29 Stakeholder Presentation December 201230 http://www.energy.alberta.ca/Initiatives/1438.asp31 http://www.transalta.com/newsroom/feature-articles/2013-05-24/project-pioneer-publishes-its-final-report-pioneer-still-sharin



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 Regulation32 (2012) SGER33 (2007)

Non-CO2 GHG Emissions BLIERs34 (in progress) CAMS35 monitoring

Renewable EnergyTax incentives: (CCA,36 CRCE,37 SR&ED38)

In-province tradable green offsets via SGER

Emerging TechnologySDTC39 ($325 million budgeted in 2013)

CCEMF40 ($213 million in 2013)41

Demand Side Management/ Energy Efficiency (DSM/EE)

Energy Efficiency Regulations C342 targeted programs43

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 Regulations33 Alberta Specified Gas Emitters Regulation34 Base-Level Industrial Emission Requirements35 Comprehensive Air Management System36 Capital Cost Allowance Classes 43.1, 43.2, 49, 737 Canadian Renewable & Conservation Expense38 Scientific Research and Experimental Development39 Sustainable Development Technology Canada40 http://ccemc.ca/media_release/climate-change-and-emissions-management-ccemc-corporation-releases-annual-report-

ccemc-funding-51-clean-tech-projects-valued-at-more-than-1-56-billion/41 Climate Change and Emission Management Fund42 Includes: Alberta’s Home Electricity Use Evaluation; municipal rebates; BioFleet; Carbon Offset Solutions; Heartland Energy

Mapping Study; Alberta Industrial Energy Efficiency Program43 http://c-3.ca/projects/



Table C-3: Electricity Consumption Drivers

Customer Sector Drivers 2013-2019 Growth

Rate

2013-2024 Growth

Rate

2013-2034 Growth

Rate

Industrial (without Oilsands)

Manufacturing GDP 2.5% 1.9% 1.8%

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 Statistically-

adjusted 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=045 http://www.eia.gov/forecasts/archive/aeo13/sector_residential.cfm



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.



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.



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



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’s47 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.asp49 http://www.cbc.ca/news/business/suncor-cancels-proposed-voyageur-upgrader-1.1362462



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

590,000 bbl/d In service N/A

TransCanada Keystone XL

830,000 bbl/d Late 2015 Included late 2015

TransCanada Energy East Conversion Line

1,100,000 bbl/dEnd of 2017 to early

2018Included 2017

Kinder Morgan TransMountain Pipeline Expansion

+590,000 bbl/d 2017 Included 2017

Enbridge Northern Gateway

520,000 bbl/d Late 2017Not in main forecast but

studied as sensitivity

Enbridge Clipper (Line 67)

+120,000 bbl/d Mid-2014 Included 2014



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

Source: AESO

Fort McMurray Area Detail

Wabamun / Edmonton Area Detail

Calgary Area DetailCoalGasCogenerationHydroWindOtherMajor Transmission Lines



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 combined-

cycle 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



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. 1552 http://www.energy.gov.ab.ca/Electricity/pdfs/AUCHydroelectricStudy.pdf



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 large-

scale 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



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.pdf55 Borealis GeoPower. CanGea 3rd Geothermal Power Forum, November 4, 2011



government conducted consultations with Albertans56 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



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 overnight57 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



Figure C-2: Comparative Generation Cost

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 prices59 (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 steam59 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.

(201

3 $C

dn/

MW

h)

$0

$50

$100

$150

$200

$250$250

$300

Combined-cycle Wind Hydro Cogeneration Simple-

cycleCoal w/

CCS

$82 $89$105 $106

$69

$110

$176

$237

PV Solar



Table C-5: LUEC Environmental Assumptions60

Main Outlook and Low Growth*

Environmental Shift

Energy Transformation

SGER

�� Annual Reduction 2% 5% 10%

�� Reduction Ceiling 12% 50% None

�� CO2 Price – 2013 $15 $25 $25

�� CO2 Price – 2020 $15 $55 $55

CCS Production Subsidy61 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



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

(201

3 $C

dn/

MW

h)

Com

bin

ed C

ycle

Win

d

Hyd

ro

Cog

en

Sim

ple

Cyc

le

Sol

ar

Coa

l w/

CC

S

Main Outlook and Low Growth Environmental Shift

Com

bin

ed C

ycle

Win

d

Hyd

ro

Cog

en

Sim

ple

Cyc

le

Sol

ar

Coa

l w/

CC

S

Energy Transformation

Com

bin

ed C

ycle

Win

d

Hyd

ro

Cog

en

Sim

ple

Cyc

le

Sol

ar

Coa

l w/

CC

S

Source: AESO


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.

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

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

Appendix E: System Load



Table E-2: System Load at AIL Peak (MW)**

YearTotal AIL Peak

LoadTotal 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



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



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

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 Description

MOD-016-AB-1.1 Documentation of Data Reporting Requirements for Actual and Forecast Demands, and Net Energy for Load

MOD-017-AB-0.1 Aggregated Actual and Forecast Demands and Net Energy for Load

MOD-018-AB-0 Reports of Actual and Forecast Demand Data

MOD-019-AB-0 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.html62 http://www.aeso.ca/downloads/MOD-016-AB-1.1.pdf

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]

AALBERTA INTERNAL LOAD

(AIL)

CNON-FIRM DEMAND

(e.g. DOS, LSSi)

BNON-RESERVE DEMAND

(e.g. BTF DEMAND)

DFIRM PEAK DEMAND

Appendix G: Alberta Reliability Standard Requirements


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.

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.



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.


This document complements the AESO’s existing publications and supports our commitment to sharing information with market participants, other stakeholders and all Albertans in a timely, open and transparent manner. Readers are invited to provide comments or suggestions for future reports.

For more information or to give us your feedback, contact [email protected]

Alberta Electric System Operator

2500, 330-5th Avenue SWCalgary, Alberta T2P 0L4

Phone: 403-539-2450Fax: 403-539-2949

www.aeso.cawww.poweringalberta.com REV 0614

aeso 2014 long-term outlook

Documents

outlook summary

energy load

economic outlook

load risks

generation risks

appendix e system load

energy commodity outlook

aeso scenarios