AESO 2016
Long-term Outlook
AESO 2016 Long-term Outlook
Table of contents
1.0 EXECUTIVE SUMMARY
Building the 2016 Long-term Outlook
1
1
Reference Case
2
Additional Scenarios
2
Key Highlights of the 2016 LTO
2.0 BACKGROUND AND METHODOLOGY
Background
3.0KEY FORECAST DRIVERS AND ASSUMPTIONS
3
4
4
6
Introduction
6
Economic Drivers and Assumptions
6
Environmental Policy Drivers and Assumptions
7
Federal Regulations
7
Provincial Regulations, Frameworks and Policies
7
Climate Change Policy
8
Coal Phase-Out
8
Renewables Support
4.0OUTLOOK REFERENCE CASE AND SCENARIO RESULTS
9
10
Introduction
10
Reference Case
10
Load
10
Generation16
Scenarios 18
High-Growth Scenario
18
Load
18
Generation18
Low-Growth Scenario
Load
18
18
Generation19
Alternate-Policy Scenario
Load
19
19
Generation19
AESO 2016 Long-term Outlook
5.0 REGIONAL OUTLOOKS
Introduction 21
21
Risks to Forecast
21
South Planning Region 22
Overview and Forecast 22
Load 22
Generation22
Risks to Forecast
23
Calgary Planning Region 23
Overview and Forecast 23
Load 24
Generation24
Risks to Forecast
24
Central Planning Region 25
Overview and Forecast 25
Load 25
Generation25
Risks to Forecast
Northwest Planning Region 26
26
Overview and Forecast 26
Load 27
Generation27
Risks to Forecast
Northeast Planning Region 27
28
Overview and Forecast 28
Load 28
Generation28
Risks to Forecast
Edmonton Planning Region 29
30
Overview and Forecast 30
Load 30
Generation30
Risks to Forecast
31
AESO 2016 Long-term Outlook
APPENDIX A
32
Supplemental Information
32
Coal Retirement Date Assumptions
32
APPENDIX B
33
Alberta Reliability Standard Requirements
33
Load Forecast Reporting to WECC
33
GLOSSARY OF TERMS 34
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 the information contained herein represents a reasonable forecast, 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.
AESO 2016 Long-term Outlook
1.0
Executive summary
The AESO 2016 Long-term Outlook describes Alberta’s expected
electricity demand over the next 20 years, as well as the expected
generation capacity needed to meet that demand.
The AESO 2016 Long-term Outlook (2016 LTO) describes key drivers of load and generation development
in Alberta, the assumptions the Alberta Electric System Operator (AESO) has made to understand
the impacts of those drivers, and the forecast results derived from them.
Alberta’s economy and electricity policies have shifted dramatically since the publishing of the AESO
2014 Long-term Outlook. Despite a weakened economic outlook for 2016, the AESO anticipates load
growth over the next three years driven by new and existing under-construction oilsands projects, a
recovery of the economy, and a restoration to more normal weather patterns in Alberta.
The 2016 LTO is based on a broad set of assumptions supported by numerous forecasts from thirdparties including the Canadian Association of Petroleum Producers (CAPP), IHS, and the National
Energy Board (NEB). The 2016 LTO assumes Alberta’s economy and corresponding load growth
will recover within the next few years and takes into account the Alberta government’s 2015 Climate
Leadership Plan (CLP), which is in the process of being refined prior to becoming law.
BUILDING THE 2016 LONG-TERM OUTLOOK
The 2016 LTO is built upon a Reference Case and three comprehensive scenarios, allowing the
AESO to create a blend of forecasts and a range of outcomes addressing potential future impacts
that are presently unknown. The 2016 LTO approaches the uncertainties currently impacting the
electricity industry through specific assumptions, and by using a range of scenarios to capture
known uncertainties and understand their impacts in a variety of potential future situations.
The Reference Case assumes moderate load growth, that the Alberta
Government will enact legislation to implement the CLP, and that the CLP
will support the addition of 4,200 MW of renewables while requiring all
coal-fired facilities to shut down by 2030.
1.0 Executive summary
1
AESO 2016 Long-term Outlook
Reference Case
The 2016 LTO’s Reference Case represents the AESO’s current expectation for future long-term load
growth and generation development, and serves as the corporate forecast informing decisions on
several areas of the AESO’s business, including transmission system planning. The Reference Case
assumes moderate load growth, that the Alberta Government will enact legislation to implement
the CLP, and that the CLP will support the addition of 4,200 MW of renewables while requiring all
coal-fired facilities to shut down by 2030.
As the province is experiencing an economic downturn at the time of the 2016 LTO’s publishing,
considerable scrutiny was given to the Reference Case’s use of a mid-growth forecast as opposed
to a low-growth forecast. The decision to use a mid-growth load forecast was based on several
factors including third-party forecasts of future oilsands development and Alberta economic growth,
especially in the long run. The AESO acknowledges the downside risk associated with the midgrowth forecast in the next 1 to 3 years. Should these third-party expectations change, the AESO
will evaluate whether one of the other forecasts, such as the Low-growth Scenario, is appropriate
to use as the new Reference Case. Further, the Reference Case, as well as all other scenarios
in the 2016 LTO, assume that measures outlined in the announced Climate Leadership Plan will
come into effect. However, until the policy becomes law, the exact measures that will be taken are
undetermined and the 2016 LTO makes assumptions about how the future climate change laws and
regulations will be finalized and implemented by the provincial government. As pieces of the Climate
Leadership Plan are finalized and implemented the AESO will track the assumptions made and will
consider updating the LTO when applicable. The information supporting the Reference Case and its
assumptions are discussed in Section 4.0 of the 2016 LTO.
Additional Scenarios
In addition to the Reference Case, three comprehensive scenarios were created for the 2016 LTO.
These provide the AESO with the necessary tools to understand potential impacts from different
load and generation outlooks so it can plan accordingly.
„„H igh-growth Scenario—assumes a robust economic recovery led by the development of
oilsands projects, and that generation and interpretation of the provincial government’s
climate change policy are similar to the Reference Case
„„Low-growth Scenario—assumes economic growth is limited due to the absence of new
oilsands projects and that generation and interpretation of the climate change policy are
similar to the Reference Case
„„Alternate-policy Scenario—combines mid-growth load expectations with an alternate
interpretation of the climate change policy
Load and generation data relating to the Reference Case and scenarios are available to market
participants and the general public. The 2016 LTO Data File can be found at www.aeso.ca/2016lto
…the AESO anticipates load growth over the next three years driven by
new and existing under-construction oilsands projects, a recovery of the
economy, and a restoration to more normal weather patterns in Alberta.
2
1.0 Executive summary
AESO 2016 Long-term Outlook
KEY HIGHLIGHTS OF THE 2016 LTO
„„T he 2016 LTO was created during a period of uncertainty arising from:
−−The current low oil-price environment
−−Undetermined policy details following the release of the province’s Climate Leadership Plan
„„T he 2016 LTO uses a Reference Case and three comprehensive scenarios to determine and
prepare for a variety of potential future outcomes
„„T he Reference Case is a mid-growth scenario as opposed to low-growth due to supporting
data and corresponding third-party forecasts as detailed in Section 4.0, which show the
mid-growth load forecast is more representative in the mid to long term. It assumes that
crude oil prices, the oilsands industry, Alberta’s economy, and load growth will recover and
continue into the future
„„T he Reference Case comprises assumptions about future load and generation development.
It assumes:
−−A lberta Internal Load (AIL) in the Reference Case grows at a relatively high pace from
2016–2018 due to oilsands projects currently under construction and a return to normal
weather conditions
−−Peak AIL will increase to 13,700 MW by 2022
−−Average peak load will grow by 1.9 per cent annually to 2037
−−Peak AIL will reach 16,500 MW by 2037
−−Approximately 7,000 MW of renewable generation will be in place by 2037
−−A pproximately 18,000 MW of simple-cycle, combined-cycle and cogeneration will be in the
generation mix by 2037
−−O ilsands production will increase by approximately 1 million barrels per day from current
levels by 2024, in line with third-party forecasts
−−T he 550,000 bbl/d of oilsands projects currently under construction will be completed and
will ramp up production and load
„„T he Reference Case assumes that the announced climate change policy will come into effect and:
−−Two-thirds of coal-fired generation capacity will be replaced by 4,200 MW of renewables
by 2030
−−All coal-fired generation will retire before 2030
„„T he High-growth Scenario uses the same generation assumptions as the Reference Case but
with higher load growth, resulting in more baseload generation development
„„T he Low-growth Scenario uses the same generation assumptions as the Reference Case but
with lower load growth, resulting in less baseload generation development
„„T he Alternate-policy Scenario assumes the same load growth as the Reference Case but with
a stronger interpretation of the announced climate change policy, resulting in:
−−M ore wind generation development compared to the Reference Case (7,200 MW added
by 2030)
−−1,000 MW of solar capacity supported and developed by 2030
−−Development of hydroelectric generation
−−More flexible generation to accommodate increased amounts of intermittent renewables
„„S cenarios test the uncertainties around future demand growth and climate change policy
„„C ombined-cycle and simple-cycle gas-fired generation will replace coal-fired generation,
support integration of intermittent renewables, and accommodate load growth
1.0 Executive summary
3
AESO 2016 Long-term Outlook
2.0
Background
and methodology
The AESO uses the 2016 Long-term Outlook (2016 LTO) as the
starting point for transmission system planning.
BACKGROUND
The 2016 LTO will be used as the foundation for the AESO’s next Long-term Transmission Plan,
which will set out the AESO’s current evaluation of Alberta’s transmission system, and describe how
the AESO will continue to provide efficient, reliable and non-discriminatory system access service
and the timely implementation of required transmission system expansions and enhancements.
The load and generation forecasts within the 2016 LTO are also an input to Needs Identification
Document (NID) filings submitted by the AESO to the Alberta Utilities Commission and are used to
support transmission connection studies conducted by electricity market participants.
While the 2016 LTO will be an input to transmission planning and NID filings, the AESO carefully
reviews the load and generation assumptions for every NID as part of its planning process. If the
load and generation assumptions of a particular project are found to be not reflective of the latest
expectations, the AESO may consider alternate load and generation for the purposes of a NID.
This is to ensure the right transmission reinforcements are considered.
The 2016 LTO is prepared in accordance with the AESO’s duties as outlined in the Province of
Alberta’s Electric Utilities Act (EUA)1 and the Transmission Regulation (T-Reg2). 3
Forecast direction, in part, is drawn from the Part 2 of T-Reg 3 which states the AESO, in planning
the transmission system:
„„M ust 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
„„M ust 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
1
www.qp.alberta.ca/documents/Acts/E05P1.pdf
2
www.qp.alberta.ca/documents/Regs/2007_086.pdf
3
www.qp.alberta.ca/1266.cfm?page=2007_086.cfm&leg_type=Regs&isbncln=9780779782314
4
2.0 Background and methodology
AESO 2016 Long-term Outlook
In addition, the Long-term Transmission Plan must include, accounting for at least the next
20 years, the following projections:
„„The forecast load on the interconnected electric system, including exports of electricity
„„T he anticipated generation capacity, including appropriate reserves and imports of
electricity required to meet the forecast load
„„T he timing and location of future generation additions, including areas of renewable or
low emission generation
The 2016 LTO was developed during a period of unprecedented uncertainty for Alberta’s electricity
industry. With low crude oil prices negatively impacting economic and load growth expectations,
and recently announced climate change policy as set out in the provincial government’s Climate
Leadership Plan, the future of Alberta’s electricity industry is highly uncertain. The 2016 LTO
approaches this by making specific assumptions and by using a range of scenarios to capture
uncertainties and understand their impacts in a variety of potential future situations.
As part of this strategy, the 2016 LTO contains a Reference Case, which is the AESO’s reference
point and corporate forecast to be used as an input to transmission planning and other purposes.
Since the AESO’s next Long-term Transmission Plan is expected to study years 2022, 2027, and
2037, those years are referenced in this document. The Reference Case represents the AESO’s
current expectation for long-run load growth and generation development given major uncertainties
facing the industry.
The Reference Case makes multiple assumptions regarding the future of load and generation
development in Alberta. It is expected that, over the course of 2016 and beyond, new information
will become available, providing direction which may differ from the assumptions outlined in this
document. The main drivers and assumptions affecting load and generation are discussed in
Section 3.0, and the Reference Case and scenario results are discussed in Section 4.0.
Alberta’s electricity industry, technologies and economy are dynamic and constantly evolving.
To ensure the 2016 LTO aligns with current and expected trends, the AESO continually monitors
relevant industry developments that may affect future load growth and generation development.
These industry-impacting developments include:
„„C hanges to Alberta’s economy, including key drivers such as the crude oil, natural gas,
and oilsands industries, as well as financial and commodity market conditions
„„P rovincial, federal and international policies and regulations concerning economic
development, the environment and the electricity industry in Alberta
„„Technological changes including generation technologies, costs and resources availability,
energy efficiency and other demand-side management initiatives
„„A nnounced, applied-for, approved, under-construction, and existing oilsands, industrial,
generation and other projects
„„Regional factors including both specific and potential sources of load and generation changes
2.0 Background and methodology
5
AESO 2016 Long-term Outlook
3.0 K
ey forecast drivers
and assumptions
INTRODUCTION
As mentioned in Section 2.0, a range of factors affects Alberta’s electricity industry. Two key factors
affecting electricity demand and supply in Alberta over the long term are economic growth and
environmental policy. This section discusses specific elements of these factors and how they affect
future load growth and generation development, along with the key assumptions made.
ECONOMIC DRIVERS AND ASSUMPTIONS
Alberta’s future economic and load growth is largely dependent on oilsands investment and
expansion. At the time of publication, oilsands-growth forecasts from third-parties such as the
Canadian Association of Petroleum Producers (CAPP)4, IHS 5, and the National Energy Board (NEB) 6
expect production in Alberta to increase from around 2.5 million barrels per day (bbl/d) today to
over 3.5 million bbl/d by 2024. As the oilsands grow, they will directly contribute to load growth. The
economic impact from their development and production will also contribute to Alberta’s economic
growth across other industry sectors, creating jobs, spurring immigration, and driving additional
economic and load growth.
However, Alberta is currently experiencing a period of very low oil prices due to a glut of oil
production in the world crude oil market. Consequently, oilsands developers have cancelled or
delayed projects, conventional oil and gas producers have reduced output, significant layoffs have
occurred, and Alberta is in the midst of an economic downturn. The restoration of oil prices to levels
that support oilsands investment and expansion is key to future economic and load growth for
the province. While forecasters are generally confident that oil prices will recover to those support
levels over the next few years, there remains considerable uncertainty around the actual timing and
magnitude of the recovery due to the various factors affecting the global crude oil market.
The 2016 LTO Reference Case is a mid-growth load scenario. It assumes relatively high growth to
2022 due to the completion of oilsands projects under construction, economic recovery due to
rising crude oil prices causing broader load growth, and the sanctioning of new oilsands projects.
After that, growth is assumed to be modest with steadier economic growth and impacts from
energy efficiency. The AESO acknowledges there is a downside risk associated with the mid-growth
load scenario over the next 1 to 3 years.
4
www.capp.ca/publications-and-statistics/publications/264673
5
IHS: Crude Oil Markets: Canadian Fundamentals data first quarter 2016
6
www.neb-one.gc.ca/nrg/ntgrtd/ftr/2016/index-eng.html
6
3.0 Key forecast drivers and assumptions
AESO 2016 Long-term Outlook
Since the resumption of economic and load growth is a key assumption to the Reference Case and
future economic growth is uncertain, the 2016 LTO contains two additional load growth scenarios.
One reflects higher growth and one lower growth, and they are designed to capture a range of
potential load growth outcomes reflective of different combinations of economic growth and
energy efficiency. The two additional load scenarios provide the AESO with the necessary tools
to understand the potential impacts from different load growth profiles so it can plan accordingly.
These scenarios, as well as the Reference Case, Alternate-policy Scenario, and their results, are
described in more detail in Section 4.0.
ENVIRONMENTAL POLICY DRIVERS AND ASSUMPTIONS
Environmental laws and policies affect the economics and incentives of market participants,
impacting the future of electricity demand and supply in Alberta. While both supply and demand
can be affected by environmental laws and policies, this section primarily focuses on those laws
and policies that will affect future generation development and the key assumptions made in the
Reference Case.
FEDERAL REGULATIONS
At the federal level, the Reduction of Carbon Dioxide Emissions from Coal-Fired Generation of
Electricity Regulations (Federal Coal Regulation) under the Canadian Environmental Protection Act
1999 set out standards for new and existing coal-fired units.7
Under the Federal Coal Regulation, new coal-fired generation facilities, as well as those at the end of
their useful life, are required to meet a performance standard matching the carbon dioxide emission
intensity of natural gas combined-cycle technology at a fixed rate of 420 tonnes per gigawatt hour.
As per the Federal Coal Regulation, coal-fired units reach their end-of-useful-life date at up to 50
years, at which time they must meet the performance standard.
The main impact of the Federal Coal Regulation is to limit the useful life of Alberta’s coal-fired units.
Of the 18 coal-fired units currently operating in Alberta, 12 are required to meet the performance
standard or retire before 2030. While coal-fired plants are able to continue operation beyond
their end-of-useful-life dates, the 2016 LTO assumes the cost of complying with the performance
standard is prohibitive, resulting in retirement.
PROVINCIAL REGULATIONS, FRAMEWORKS AND POLICIES
At the provincial level, there are several environmental requirements that impact Alberta’s electricity
industry including the Specified Gas Emitters Regulation (SGER) and the Clean Air Strategic Alliance
(CASA) Electricity Emissions Management Framework.
The SGER requires all industrial facilities, including electricity generators, which emit more than
100,000 tonnes of greenhouse gases per year, to reduce their corresponding emission intensities.
Compliance can be met by making improvements at facilities to reduce emissions, purchasing
emission offset credits, using performance credits generated at facilities that achieve more than
the required reductions, or making financial contributions to the Climate Change and Emission
Management Fund. Currently, the SGER is the status quo carbon emission regulation for large
emitters, including generation, and is set to expire December 31, 2017. At that time, it is expected
that new legislation (discussed in the next section) will replace it.
7
www.ec.gc.ca/cc/default.asp?lang=En&n=C94FABDA-1
3.0 Key forecast drivers and assumptions
7
AESO 2016 Long-term Outlook
The CASA Electricity Emissions Management Framework is a framework for managing air pollution,
developed by a multi-stakeholder alliance composed of representatives from industry, government,
and non-government organizations. The alliance is tasked with providing strategies to assess and
improve air quality for Albertans using a collaborative consensus process. Under this framework,
all coal-fired generating units will have to comply in their environmental permits with sulphur dioxide
(SO2) and nitrogen oxides (NOX) emission standards at the end of design life. Units can comply with
CASA through credits, installing abatement equipment, or by retiring.
The requirements, laid out in Alberta Air Emissions Standards for Electricity Generation and Alberta
Air Emission Guidelines for Electricity Generation 8, have the potential to impact the economics
and retirement dates of coal-fired facilities. However, due to the complexity and flexibility of
compliance options, the 2016 LTO does not explicitly assume impacts to retirement dates resulting
from CASA. Instead, specific assumptions around coal-fired unit retirements are made and
discussed in detail below.
CLIMATE CHANGE POLICY
On November 22, 2015, the Alberta government released its Climate Leadership Plan (CLP) 9.
The policy includes several elements that will significantly alter the future of Alberta’s electricity
industry. However, key details of the policy are still to be determined as of the 2016 LTO publishing
date. In order to assess potential impacts of the policy, the 2016 LTO makes assumptions using the
announcement of the CLP as well as the associated Climate Leadership Report to Minister (CLRM)10
as guidance to the government’s intentions, knowing there remains uncertainty until details are
finalized and the policy is implemented. The key policy elements impacting the 2016 LTO are early
coal phase-out and support for renewables. There are other announced policy initiatives which
could impact the forecast including:
„„Implementing a new price on CO2 for coal-fired generators based on an industry-wide
performance standard
„„L egislating oilsands emission limits
„„Adopting a hybrid regulatory and market-based approach to reduce emissions from
oil and gas
„„E nabling the creation of energy efficiency and energy-resilient communities
„„E nabling technology and innovation that can further mitigate climate change
Coal Phase-Out
The CLP states there will be no pollution from coal-fired electricity generation by 2030. This is
assumed to mean that coal-fired units will be required to retire and be phased out by 2030, implying
that at least six coal-fired units will be required to retire before their federal end-of-useful-life dates.
As part of the climate change policy announcement, the Government of Alberta has appointed
a coal facilitator to implement the coal phase-out. It is unknown at the time of the 2016 LTO’s
publication what the schedule of coal-fired retirement will be and therefore, assumptions are made
regarding that schedule. For the Reference Case, it is assumed that the coal-fired unit retirement will
be “back-loaded” in that the majority of retirements will occur in the late 2020s.
8
www.environment.gov.ab.ca/info/library/7837.pdf
9
www.alberta.ca/climate-leadership-plan.cfm
10
www.alberta.ca/documents/climate/climate-leadership-report-to-minister.pdf
8
3.0 Key forecast drivers and assumptions
AESO 2016 Long-term Outlook
It is assumed that the coal-fired units will remain a part of the industry and market until then and
will remain active due to economic or reliability reasons, or both. The Reference Case also assumes
that no more than 1,600 MW of coal-fired generation will retire per year, reflective of assumptions
regarding the limited capability to build and commission new non-intermittent generation. It is
possible that actual retirement of coal-fired units may occur sooner, as a result of economics or
other factors, and at a pace different than assumed in the Reference Case. The Alternate-policy
Scenario tests a different coal retirement schedule that is more front-loaded and has a significant
number of units retiring in the early 2020s.
The assumed coal-fired generation retirement schedule for the Reference Case can be found in
Appendix A.
RENEWABLES SUPPORT
An indication of support for renewables implies that at least some build level of renewable
generation is expected. However, it is not certain at the time of the 2016 LTO’s publication what
level and type of support will occur. Additional renewables will also affect the types and amounts of
non-intermittent generation required to support the often quick up-and-down ramping of intermittent
renewable generation. The 2016 LTO Reference Case assumes that 350 MW of renewable capacity
will be built each year from 2018–2029, resulting in 4,200 MW of renewable capacity built.
An additional assumption is that all of this renewable capacity will be wind generation. Presently,
wind generation is the lowest-cost established renewable technology that can make up the assumed
4,200 MW. This is built upon the assumption that other renewable technology types will not reach
a competitive cost level with wind by 2030. However, it is possible that before then, technologies
such as solar, hydroelectric, geothermal, and/or biomass will become part of the renewables mix.
This could happen due to favourable economics which could include improving costs in the future,
explicit renewables program support for specific technologies, or future generation resource
limitations on other technologies.
Other policy initiatives could impact the relative costs of different generation technologies including
the announced carbon levy. High carbon-emitting generators will face higher costs under a carbon
levy compared to lower-emitting generators, which could impact investment and retirement
decisions and operating and energy market behavior. These other policy initiatives are modelled in
the 2016 LTO to understand the impact.
Based on the CLP, there is no expected support for large-scale energy storage. While there is
potential for energy storage in Alberta including existing proposed projects, the 2016 LTO has not
assumed significant storage development.
The Reference Case, as well as all other scenarios in the 2016 LTO, assumes that measures
outlined in the announced policy will come into effect. However, until the policy becomes law, the
exact measures that will be taken are undetermined. So while the 2016 LTO makes assumptions
about future climate change laws and regulations, these remain to be finalized and implemented by
the provincial government. Section 4.0 describes load and generation results occurring from the
assumptions made in the Reference Case and compares them with alternate scenarios.
3.0 Key forecast drivers and assumptions
9
AESO 2016 Long-term Outlook
4.0 O
utlook reference case
and scenario results
INTRODUCTION
The 2016 Long-term Outlook (2016 LTO) comprises a Reference Case and three comprehensive
scenarios. This blend of forecasts provides the AESO with a range of future outcomes that captures
forecast uncertainty. The Reference Case is the AESO’s forecast for initial consideration, and
the other scenarios will be used for testing to understand impacts from uncertainty. This section
discusses the results from the Reference Case and scenarios.
The data associated with the AESO’s Reference Case and scenarios, and assumptions within them,
are available to market participants and the public. The 2016 Data File can be found at
www.aeso.ca/2016lto
2016 LTO scenarios
Economic/Load growth
FIGURE 1: 2016 LTO scenarios
High growth
Reference case
(Mid growth)
Alternate policy
(Mid growth)
Low growth
Environmental policy
REFERENCE CASE
Load
The Reference Case is based on a mid-growth load forecast which assumes a recovery in crude
oil prices and corresponding oilsands development. Despite a weakened economic outlook for
2016, the AESO anticipates relatively strong load growth over the next three years driven by new
and existing under-construction oilsands projects, a recovery in the economy, and a return to more
normal* weather patterns (*Normal is based on a 40-year historical average. See Table 2). It is noted
that the province is experiencing an economic downturn at the time of the LTO’s publishing, with
resultant stagnant load growth in 2015. However, the load forecast of mid-growth, as opposed to
low-growth, is well-supported by current data and other third-party forecasts, especially in the mid
and long term.
Alberta Internal Load (AIL) in the Reference Case grows at a relatively high pace from 2016–2018
(see Table 1), with peak AIL increasing to 13,700 MW by 2022. Post-2022, load growth is assumed
to continue, albeit modestly, due to a reduced pace of development and improved energy efficiency.
Peak AIL in the Reference Case is assumed to grow at an average annual rate of 2.5 per cent to
2027 and 1.9 per cent to 2037.
10
4.0 Outlook reference case and scenario results
AESO 2016 Long-term Outlook
A contributing factor to the relatively high near-term growth in the Reference Case is that 2015 AIL
growth was an outlier compared with the previous five years. From 2010–2014, average AIL grew by
at least 200 MW each year, driven by oilsands project development and associated economic and
population growth. Average 2015 AIL grew by only 35 MW over 2014.
TABLE 1: Recent and near-term forecast reference case load
Year
Average
AIL (MW)
Annual
Average
Growth (MW)
2010
2011
2012
2013
2014
2015 2016F
2017F
8,188
8,402
8,604
8,841
9,127
9,162
9,597
9,868 10,151 10,439 10,711
214
202
237
286
35
435
271
2018F 2019F 2020F
283
288
272
Note: “F” denotes Reference Case forecast values, all else is historical. Source: AESO
The AESO has identified two main factors contributing to low 2015 AIL growth. First, winter weather
in 2015 was milder than 2014 weather, as well as compared to historical averages. Secondly,
Alberta’s economy entered into a recession due to a significant decrease of crude oil prices.
Table 2 shows a comparison of 2014–2016 weather, as measured by Heating Degree Days (HDD),
Cooling Degree Days (CDD), and long-run averages. There were 659 fewer (22 per cent less) HDDs
in 2015 than in 2014, meaning 2015 experienced significantly less heating-related load than 2014. In
addition, CDD, which impacts cooling-related load, was not significantly different in 2015 compared
to 2014. Visually, these impacts can be seen in Figure 2.
The AESO estimates that overall, 2015 experienced 40 MW of lower average AIL than 2014 due to
weather. The Reference Case reflects the expectation that subsequent winters will follow normal
expected trends.
TABLE 2: C
omparison of 2014 to 2016 and normal* heating degree days and cooling degree days
Month
2014
HDD
2015
HDD
2016
HDD
Normal*
HDD
2014
CDD
2015
CDD
Normal*
CDD
Jan
491
486
521
600
0
0
0
Feb
660
508
314
472
0
0
0
Mar
508
237
232
380
0
0
0
Apr
169
108
-
140
1
4
0
May
56
25
-
8
30
39
2
Jun
2
0
-
0
82
157
67
Jul
0
0
-
0
235
214
142
Aug
0
0
-
0
175
171
112
Sep
33
18
-
0
47
22
6
Oct
74
84
-
130
2
9
0
Nov
481
330
-
382
0
0
0
Dec
474
494
-
556
0
0
0
2,948
2,289
1067
2,668
571
615
328
Total
Source: AESO, Environment Canada
HDD: Heating Degree Days using a base of 9 degrees Celsius
CDD: Cooling Degree Days using a base of 12 degrees Celsius
* Normal is based on a 40-year historical average
4.0 Outlook reference case and scenario results
11
AESO 2016 Long-term Outlook
FIGURE 2: Average
Alberta
Internal Load (AIL) and average Alberta temperatures
Average Alberta
Internal Load
(AIL)
10,500
10,000
Average AIL (MW)
9,500
9,000
8,500
8,000
7,500
7,000
6,500
6,000
Jan
2010
Feb
2011
Average Alberta temperatures
Mar
2012
Apr
2013
2014
May
2015
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jul
Aug
Sep
Oct
Nov
Dec
2016
25
20
Average temperature
15
10
5
0
-5
-10
-15
-20
Jan
2010
Feb
2011
Mar
2012
Apr
2013
2014
May
2015
Jun
2016
Source: AESO, Environment Canada
In addition to weather impacts, a slowdown in the Alberta economy also impacted 2015 load growth
over 2014. Figure 3 shows historical Alberta employment data. Employment is a reliable measure of
provincial economic health and is updated monthly allowing for an assessment of recent trends and
changes. Furthermore, employment has demonstrated strong correlation with AIL, indicating it is a
useful economic driver of load growth.
The chart in Figure 3 indicates that, from late 2010, the number of workers in Alberta steadily
increased to a peak in January 2015. After that, the number decreased, especially in the last three
months of the year and into 2016. Based on these employment numbers, and controlling for factors
like weather, the AESO estimates that if employment had remained flat at January 2015 values (the
red line on the chart), January 2016 average AIL would have been approximately 130 MW higher.
If employment had continued to increase in line with its historical linear growth rate (the green line on
the chart), January 2016 average AIL would have been approximately 365 MW higher than actuals.
12
4.0 Outlook reference case and scenario results
AESO 2016 Long-term Outlook
FIGURE 3: Historical
Historical Alberta
employmentAlberta employment
2,600
Alberta employment (thousands)
2,500
2,400
2,300
2,200
2011
2013
Max people employed
Jul
Oct
Apr
Jan
Jul
2017
Oct
Apr
Jan
Jul
2016
Oct
Apr
Jan
Jul
2015
Oct
Apr
Jan
Jul
2014
Oct
Apr
Jan
Jul
Oct
Apr
Jan
Jul
2012
People employed (000)
Oct
Apr
Jan
Jul
Oct
Apr
Jan
Jul
2010
Oct
Apr
2,000
Jan
2,100
2018
Historic trend
Source: AESO, Cansim Table 282-0088
2015 AIL also showed regional differences in load growth. Most of the province experienced
negative load growth related to the aforementioned weather and economic impacts. However,
two areas bucked this trend. Both the Fort McMurray area (Area 25, see map on page 21) and the
Cold Lake area (Area 28, see map on page 21) demonstrated significant load growth in 2015 over
2014 due to the completion and ramping up of major oilsands projects. The effect of decreasing
load growth in most areas, simultaneous with increasing oilsands load, resulted in a net 2015 AIL
increase of 0.4 per cent (an average of 35 MW higher in 2015).
2015 AIL, especially compared to 2014, is important because 2015 is expected to be an outlier due
to mild weather in combination with economic impacts, both of which are expected to be temporary.
It can be expected that AIL growth rates will increase with typical winter weather conditions.
The impact of low crude oil prices on Alberta’s economy and load growth is also expected to be
temporary. Recent third-party forecasts, as shown in Figure 4, indicate that Alberta is expected to
return to positive economic growth by 2017. Once economic growth resumes in Alberta, jobs will
increase and it is expected that the AIL impacted by the economic downturn will return.
4.0 Outlook reference case and scenario results
13
AESO 2016 Long-term Outlook
FIGURE 4: Alberta
short-term
real GDP growth forecasts
Alberta short-term
real GDP
growth
8.0%
Alberta GDP Growth
6.0%
4.0%
2.0%
0.0%
-2.0%
-4.0%
-6.0%
2004
2005
Historical
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
Alberta Treasury (Feb 2016)
CIBC (Mar 2016)
BMO (Mar 2016)
Conference Board (Feb 2016)
TD (Jan 2016)
RBC (Mar 2016)
2016
2017
Sources: (as above)
AIL growth in the Reference Case is driven by a couple of sources. In the very near term, normal
weather and an economic rebound are expected to contribute to load growth. While the load growth
projected in 2016 under the Reference Case is consistent with the economic recovery occurring that
year, the AESO recognizes there is inherent uncertainty around the near-term timing of that recovery
along with downside risk associated with near-term load growth.
Additional near-term load growth in the Reference Case is also expected from oilsands projects
which are currently under construction. Figure 5 shows the cumulative additional capacity from
oilsands projects under construction, as well as other projects under various stages of regulatory
approval. Currently, there is over 550,000 bbl/d of under-construction oilsands capacity. In addition
to the projects identified in Figure 5, there is an additional 3.7 million bbl/day of capacity which has
been announced but which does not have a stated in-service date.
14
4.0 Outlook reference case and scenario results
AESO 2016 Long-term Outlook
FIGURE 5: Oilsands
production capacity additions by current status
Oilsands production
capasity
6,000
Oilsands production (kbbl/d)
5,000
4,000
3,000
2,000
Announced
Applied
Approved
On Hold
Under Construction
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
0
2004
1,000
Operating
Source: Government of Alberta, Oilsands Review and IHS Energy
Beyond 2017, AIL is forecast to continue to grow due to a number of factors. In 2018, additional
load growth is anticipated from the ramping up of oilsands projects that were completed earlier but
have not yet fully ramped up production. Also, by the end of 2017, it is estimated that expansions at
existing oilsands projects will be economic. Expansion at existing sites is quicker than new projects
and will add to load growth in 2018 and beyond. Once new oilsands projects are sanctioned, it is
expected that the positive economic impact will drive load growth through pipeline expansions and
new job creation will result, spurring immigration and overall economic growth.
The expectation that oilsands will continue to grow beyond existing under-construction projects
is supported by third-party forecasts, including IHS, CAPP, and the NEB, who all expect oilsands
production to increase by approximately 1,000,000 bbl/d from current levels by 2024 (see Figure 6).
The decision to use a mid-growth forecast was based on several factors including third-party
forecasts of future oilsands development and Alberta economic growth especially in the longer term.
Should these third-party expectations change, the AESO will evaluate whether one of the other
forecasts, such as the Low-growth Scenario, is appropriate to use as the new Reference Case.
While short-term indicators are testing or challenging the growth levels considered in the mid-growth
case, there are short-term indicators (weather impacts, projects under construction) and longer-term
indicators (forecast economic recovery, forecast oilsands growth) that provide the AESO with signals
at this time that the mid-growth load scenario is appropriate as the Reference Case.
It is important to note that the AESO carefully considers all drivers of the need for transmission
reinforcement including load and generation assumptions, and it will not propose or file a NID without the proper due diligence of need.
4.0 Outlook reference case and scenario results
15
AESO 2016 Long-term Outlook
FIGURE 6: Oilsands
production forecasts
Oilsands production
forecast
4,500
4,000
Oilsands production (kbbl/d)
3,500
3,000
2,500
2,000
1,500
1,000
500
0
2013
2014
CAPP 2015
2015
2016
2017
IHS 2016
2018
2019
2020
2021
2022
2023
2024
2025
NEB 2016
Sources: CAPP – 2015 Crude Oil Forecast, Markets & Transportation11
IHS – Canadian Fundamentals data – 2016
NEB – Canada’s Energy Future 2016: Energy Supply and Demand Projections to 204012
Generation
The generation outlook is developed based on the load forecast as it is assumed that generation
capacity will develop such that it will reliably serve load. The 2016 LTO Reference Case is strongly
impacted by the Climate Leadership Plan (CLP) and associated Climate Leadership Report to
Minister (CLRM) which identify the intention to phase out coal-fired generation and replace it with
renewables. The Reference Case assumes most coal-fired units will retire in the late 2020s as per
the CLP which states pollution from coal-fired sources of electricity will be phased out completely by
2030. The CLRM advises that 50 to 75 per cent of that retired coal-fired generating capacity will be
replaced with renewables by 2030.13
The Reference Case assumes that 350 MW of renewables will be added per year starting in 2018,
in line with the CLRM guidance that 350 MW of new renewable capacity be available by 2018. By
adding 350 MW of renewable capacity per year starting in 2018, 4,200 MW will be added by 2030
and provide up to 30 per cent of total installed generation. 4,200 MW is equal to two-thirds of the
existing coal-fired capacity being replaced with renewables.
There are a variety of renewable generation technologies that could be developed to meet the goals
of the CLP, such as wind, solar, geothermal, biomass and hydroelectric. Solar and wind generation
are seen as the most likely to develop as they are mature technologies with relatively low upfront
capital costs. As the CLRM indicated, new wind generation requires average revenue between
$60-$80/MWh while solar would likely require prices well above $100/MWh to guarantee construction.
Due to the cost advantages and large resource potential of wind generation, the Reference Case
assumes it is the technology supported thus adding 4,200 MW of wind capacity by 2030. It is
possible that other technologies, such as solar generation, may also become supported with higher
pool prices, substantial decreases in capital costs, or specific government support for generation.
11
www.capp.ca/publications-and-statistics/publications/264673
12
www.neb-one.gc.ca/nrg/ntgrtd/ftr/2016/index-eng.html
13
www.alberta.ca/climate-leadership-plan.cfm
16
4.0 Outlook reference case and scenario results
AESO 2016 Long-term Outlook
Both geothermal and hydroelectric generation, while providing better baseload generation
profiles, have large upfront capital costs and difficult regulatory processes that make near-term
development difficult.
With coal-fired retirements and continued load growth, new non-intermittent generation will need
to develop to ensure supply adequacy. The most likely technologies are gas-fired cogeneration,
simple-cycle, and combined-cycle (including coal-to-gas conversion). Gas-fired generation
has relatively low capital costs, can be developed quickly, and is a lower-emissions generation
type compared to coal-fired generation. Gas-fired generation is also flexible in that it can follow
intermittent generation sources such as wind and solar, making it complementary to the CLP’s
support for renewables.
Other large-scale technologies such as hydroelectric and nuclear generation are available to support
baseload power growth, but these technologies have large capital costs and challenging regulatory
processes that make them difficult to develop in a timely manner. The Reference Case shows gasfired generation developing to meet future load. By 2030, to meet retirements and load growth, there
is over 9,200 MW of gas-fired cogeneration, simple-cycle and combined-cycle additions.
Figure 7 summarizes the generation additions and retirements by generation technology for key
study years.
Generation7:capacity
mix comparison
FIGURE Generation
capacity mix comparison
Existing
2022
2027
2030
2037
AIL peak: 11,229 MW
AIL peak: 13,701 MW
AIL peak: 14,702 MW
AIL peak: 15,230 MW
AIL peak: 16,496 MW
39%
28%
11%
6%
5%
9%
3%
Coal-fired
Cogeneration
Combined-cycle
Simple-cycle
Hydroelectric
Wind
Other
Total capacity
6,289
4,502
1,716
996
894
1,463
428
16,288 MW
28%
27%
13%
8%
5%
16%
2%
Coal-fired
Cogeneration
Combined-cycle
Simple-cycle
Hydroelectric
Wind
Other
Total capacity
5,420
5,353
2,626
1,499
894
3,213
469
19,474 MW
4.0 Outlook reference case and scenario results
20%
24%
20%
7%
4%
22%
2%
Coal-fired
Cogeneration
Combined-cycle
Simple-cycle
Hydroelectric
Wind
Other
Total capacity
4,491
5,406
4,446
1,642
894
4,963
469
22,311 MW
0%
24%
36%
10%
4%
24%
2%
Coal-fired
Cogeneration
Combined-cycle
Simple-cycle
Hydroelectric
Wind
Other
Total capacity
0
5,548
8,541
2,307
894
5,663
469
23,422 MW
0%
23%
38%
11%
4%
23%
2%
Coal-fired
Cogeneration
Combined-cycle
Simple-cycle
Hydroelectric
Wind
Other
0
5,690
9,451
2,877
894
5,663
469
25,044 MW
Total capacity
17
AESO 2016 Long-term Outlook
SCENARIOS
The following three scenarios model and anticipate potential future load, generation, economic
and policy outcomes that differ from outcomes considered in the Reference Case. Through these
scenarios, the AESO is able to capture forecast uncertainties and determine potential impacts.
Data for alternate scenarios can be found online in the 2016 LTO Data File at www.aeso.ca/2016lto
HIGH-GROWTH SCENARIO
Load
The High-growth Scenario assumes a robust economic recovery beginning in 2016 led by the
development of major oilsands projects including many which have recently been postponed or
deferred. Load growth in this scenario is near-term weighted due to the completion and ramping up
of oilsands projects currently under construction.
This scenario has an average annual peak load growth of 4.3 per cent to 2022. Over the longer term,
greater uncertainty about future oilsands and other development in the province, reduced oilsands
and economic growth, and improvements in energy efficiency result in a lower rate of load growth.
However, the High-growth Scenario has the highest long-run load growth rate of all the scenarios
with an average annual peak load growth rate of 3.3 per cent to 2027, and 2.5 per cent to 2037. The
High-growth Scenario allows the AESO to test a high-growth case should crude oil prices rebound
with long-term expectations for strong economic and load growth.
Generation
The policy and generation addition assumptions in the High-growth Scenario are generally the same
as the Reference Case, as both have the same coal-fired generation retirement schedule and the
same 4,200 MW of renewables (wind) additions. However, other results are somewhat different
due to the higher load-growth expectation in this scenario. The additional oilsands projects in the
High-growth Scenario, compared to the Reference Case, result in higher levels of cogeneration
development. Additionally, because of higher load growth, more combined-cycle capacity is added
compared to the Reference Case.
LOW-GROWTH SCENARIO
Load
The Low-growth Scenario assumes existing and under-construction oilsands projects remain
operating, but no new projects beyond these proceed. Because it contains projects currently under
construction, those projects contribute to near-term load growth, resulting in front-end loaded
growth in this scenario with an average annual peak load growth rate of 2.3 per cent to 2022. In the
long run, growth is positive but tepid as the lack of oilsands expansion and economic growth results
in relatively minor, though still positive, load growth in Alberta. In the Low-growth Scenario, peak AIL
grows at an average annual rate of 1.8 per cent to 2027 and 1.3 per cent to 2037.
18
4.0 Outlook reference case and scenario results
AESO 2016 Long-term Outlook
Generation
With similar generation and climate change policy assumptions as the Reference Case, renewables
development is the same with 4,200 MW of wind capacity built by 2030. Cogeneration development
is less than the Reference Case because only operating and under-construction oilsands projects
are assumed to be included. Since load growth is lower in this scenario, less combined-cycle
capacity is built.
ALTERNATE-POLICY SCENARIO
Load
The Alternate-policy Scenario uses the mid-growth load case combined with an alternate
interpretation of the announced climate change policy. By using the same load growth as the
Reference Case, a direct comparison of policy impacts can be measured.
Generation
There are two major assumption changes in the generation outlook of the Alternate-policy Scenario
compared to the Reference Case. First, the assumed coal-fired generation retirement schedule is
more front-end loaded compared to the Reference Case. Units are generally assumed to retire at
a 40-year end-of-design-life date but after their Power Purchase Arrangements (if any) expire and
before 2030. Table 16 in Appendix A shows unit-by-unit retirement dates for all coal-fired generation
by scenario.
The second assumption change is instead of assuming 4,200 MW of renewables are added, there is
support for 9,300 MW of renewables by 2037. It is also assumed that renewables additions are not
all wind generation. In the Alternate-policy Scenario, it is assumed that there will be support for solar
and large-scale hydroelectric generation as well. Starting in 2018, 600 MW of wind generation is
added annually and 100 MW per year of solar generation is added annually beginning in 2020.
As well, 330 MW of hydroelectric generation14 is added in 2027 with an additional 770 MW in 2036.
Because of the higher levels of intermittent (wind and solar) renewables development which have
relatively fast up-and-down ramp rates, the mix of non-intermittent generation is different compared
to the Reference Case with more simple-cycle and less combined-cycle capacity added.
14
The hydroelectric addition in 2027 is based on the assumption that with support a moderately sized 300 MW hydro project could
move forward in the ten year time frame. The announced 330 MW Amisk Hydroelectric project is one example. As well other
development opportunities exist in Alberta.
5.0 Regional outlooks
19
AESO 2016 Long-term Outlook
TABLE 3: Reference Case and Scenario Load Peak and Installed Generation by Type (MW)
2022
Demand
Generation
Reference Case
Alternate Case
Low Growth
High Growth
AIL Peak
13,701
13,701
12,919
14,781
Coal-fired
5,420
3,299
5,420
5,420
Cogeneration
5,353
5,353
5,113
6,358
Combined Cycle
2,626
3,596
1,716
2,171
Simple Cycle
1,499
2,307
1,452
1,599
Hydro
894
894
894
894
Wind
3,213
4,463
3,213
3,213
Solar
0
300
0
0
Other
469
469
469
469
Total
19,474
20,681
18,277
20,124
Reference Case
Alternate Case
Low Growth
High Growth
14,702
14,702
13,530
16,130
2027
Demand
Generation
AIL Peak
Coal-fired
4,491
1,719
4,491
4,491
Cogeneration
5,406
5,406
5,148
6,526
Combined Cycle
4,446
5,356
3,111
4,416
Simple Cycle
1,642
3,494
1,689
1,884
Hydro
894
894
894
894
Wind
4,963
7,463
4,963
4,963
Solar
0
800
0
0
Other
469
469
469
469
Total
22,311
25,601
20,765
23,643
Reference Case
Alternate Case
Low Growth
High Growth
AIL Peak
15,230
15,230
13,822
17,019
Coal-fired
0
0
0
0
2030
Demand
Generation
Cogeneration
5,548
5,548
5,148
6,810
Combined Cycle
8,541
7,176
7,631
9,421
Simple Cycle
2,307
3,684
2,354
2,359
Hydro
894
1,224
894
894
Wind
5,663
8,663
5,663
5,663
Solar
0
1,000
0
0
Other
469
469
469
469
Total
23,422
27,764
22,159
25,616
Reference Case
Alternate Case
Low Growth
High Growth
AIL Peak
16,496
16,496
14,545
18,823
Coal-fired
0
0
0
0
Cogeneration
5,690
5,690
5,148
7,002
Combined Cycle
9,451
7,631
8,541
11,241
Simple Cycle
2037
Demand
Generation
2,877
3,684
2,354
2,359
Hydro
894
2,024
894
894
Wind
5,663
8,663
5,663
5,663
Solar
0
1,000
0
0
Other
469
469
469
469
Total
25,044
29,161
23,069
27,628
Source: AESO
20
4.0 Outlook reference case and scenario results
AESO 2016 Long-term Outlook
5.0 Regional Outlooks
INTRODUCTION
The 2016 LTO is an input to AESO transmission planning and examines the features of each specific
AESO Planning Region as well as key drivers affecting load and generation within those regions.
Assessing these elements by region assists the AESO in understanding the geographical impacts
associated with forecast load and generation. The forecast results outlined in this section are
aligned with the Reference Case forecast and its assumptions.
A data file outlining region-specific load and generation info can be found at www.aeso.ca/2016lto
Risks to Forecast
AESO
transmission
planning areas
AESO
Each Planning Region section includes a section regarding risk. The term “risk” applies specifically
to the Reference Case results and potential uncertainty due to identified, but presently unexpected,
potential load and generation changes within the region.
17
18
transmission
NUMERICAL
ALPHABETICAL
planning areas
25
17
18
25
19
Fort McMurray
Peace River
19
20
Fort McMurray
Peace River
21
20
23
Grande Prairie
21
23
Grande Prairie
27
26
24
22
24
22
40
40
29
38
44
39
Northwest
Northeast
Northwest
Northeast
Edmonton
Major city or town
44
37
37
43
42
45
Calgary
47
48
Brooks
49
43
54
53
52
Lethbridge
45
55
46
47
Medicine Hat
4
48
Brooks
Central
49
South
53
Calgary
Edmonton
Major city or town
57
6
57
6
Calgary
32
42
36
39
46
Central
Calgary
36
38
35
Red Deer
South
32
31Red Deer
34
13
13
31
35
30
34
56
56
Edmonton
30 Edmonton
Planning Regions
33
3360
60
29
Planning Regions
28
28
27
26
4 Medicine Hat
34 Abraham Lake
6 Calgary
57 Airdrie
13 Lloydminster
36 Alliance/Battle River
17 Rainbow Lake
27 Athabasca/Lac La Biche
18 High Level
47 Brooks
NUMERICAL
ALPHABETICAL
19 Peace River
6 Calgary
4 Medicine Hat
34 Abraham Lake
20
Grande
Prairie
38
Caroline
6 Calgary
57 Airdrie
13 Lloydminster
36 Alliance/Battle28
RiverCold Lake
21 High Prairie
17 Rainbow Lake
27 Athabasca/Lac La Biche
22 Grande Cache 47 Brooks
39 Didsbury
18 High Level
23 River
Valleyview
30 Drayton Valley
19 Peace
6 Calgary
20 Grande
Prairie
38
Caroline
24 Fox Creek
60 Edmonton
21 High Prairie
28 Cold Lake
25 Fort
48 Empress
22 Grande
CacheMcMurray 39 Didsbury
23 Valleyview
30 Drayton Valley53 Fort Macleod
26 Swan Hills
24 Fox
Edmonton
27Creek
Athabasca/Lac La60Biche
25 Fort McMurray
25 Fort McMurray
48 Empress
28 Hills
Cold Lake
26 Swan
53 Fort Macleod 33 Fort Saskatchewan
27 Athabasca/Lac
La
Biche
25
Fort
McMurray
29 Hinton/Edson
24 Fox Creek
28 Cold Lake
Fort Saskatchewan
30 Drayton Valley 33
55 Glenwood
29 Hinton/Edson
24 Fox Creek
31 Wetaskiwin
22 Grande Cache
30 Drayton
Valley
55 Glenwood
31 Wetaskiwin
22 Grande Cache20 Grande Prairie
32 Wainwright
32 Wainwright
20 Grande Prairie
33 Fort Saskatchewan
42 Hanna
33 Fort Saskatchewan
42 Hanna
34
Abraham
Lake
34 Abraham Lake
21 High Prairie 21 High Prairie
35 Red
18 High Level 18 High Level
35Deer
Red Deer
36 Alliance/Battle River
46 High River
36 Alliance/Battle River
37 Provost
29 Hinton/Edson 46 High River
38 Caroline
54 Lethbridge 29 Hinton/Edson
37 Provost
39 Didsbury
13 Lloydminster 54 Lethbridge
38 Caroline
40 Wabamun
4 Medicine Hat
39 Didsbury
42 Hanna
19 Peace River 13 Lloydminster
43 Sheerness
37 Provost
40 Wabamun
4 Medicine Hat
44 Seebe
17 Rainbow Lake
42 Hanna
19 Peace River
45 Strathmore/Blackie
35 Red Deer
43 River
Sheerness
37 Provost
46 High
44 Seebe
47 Brooks
43 Sheerness 17 Rainbow Lake
44 Seebe
48 Empress
49 Stavely
45
Strathmore/Blackie
35
Red Deer
49 Stavely
45 Strathmore/Blackie
46 High River
52 Vauxhall
26 Swan Hills 44 Seebe
53 Fort
Macleod
23
Valleyview
47 Brooks
43 Sheerness
54 Lethbridge
52 Vauxhall
48 Empress
49 Stavely
55 Glenwood
56 Vegreville
56 Vegreville
40 Wabamun
49 Stavely
45 Strathmore/Blackie
57 Airdrie
32 Wainwright 26 Swan Hills
52 Vauxhall
60 Edmonton
31 Wetaskiwin
53 Fort Macleod
23 Valleyview
54 Lethbridge
52 Vauxhall
55 Glenwood
56 Vegreville
56 Vegreville
40 Wabamun
57 Airdrie
32 Wainwright
60 Edmonton
31 Wetaskiwin
54
Lethbridge
52
Medicine Hat
4
55
5.0 Regional outlooks
21
AESO 2016 Long-term Outlook
SOUTH PLANNING REGION
Overview and Forecast
The South Planning Region encompasses southern Alberta and includes Lethbridge, High River,
Brooks, and Medicine Hat. It contains approximately 10 per cent of the province’s population.
This region is generally summer-peaking with higher air conditioning use and seasonal irrigation loads.
TABLE 4: South Planning Region
2015 Average Load (MW)
1,026
2015 Summer Peak (MW)
1,421
2015/2016 Winter Peak (MW)
1,192
Population (000s)
Area (000km 2)
407
91
Load
The South Planning Region represents about 11 per cent of Alberta Internal Load (AIL), and contains
the majority of provincial farm demand and some industrial load including pipelines, manufacturing,
and natural gas processing.
Over the past 10 years, summer peak load has grown by an average annual rate of 0.9 per cent.
Under the Reference Case, the region’s summer peak is expected to grow at a rate of 1.5 per cent
annually until 2037, due to residential, commercial, and industrial development associated with the
province’s overall economic and population growth.
Generation
The South Planning Region has shown large growth in generation development over the last 10 years.
These additions have come primarily from wind-power generation with over 950 MW of new
development. In addition to the development of wind resources, the South Planning Region has
seen small increases in gas-fired generation, hydroelectric generation, and coal-fired capacity.
Overall, the region has increased generation capacity by over 1,000 MW in the past 10 years.
The region currently contains coal-fired, gas-fired, wind-powered, and hydroelectric generation
technologies and has a total generation capacity of 2,900 MW.
The future potential in the region is heavily weighted to renewables, with large potential for
development of wind and solar resources. Gas-fired projects have also been proposed and could
add generation in the region. Gas-fired additions are included in the long term.
The regional forecast assumes near-term development of wind power and development of small
gas-fired facilities. In the long term, continued development of renewables is assumed, with wind
being the primary source. Wind capacity within the forecast was allocated across regions based on
the regional distribution of projects within the AESO connection process.
There is also a coal-fired facility in the South Region. Under announced provincial climate change
policy and current federal regulations, the facility will be required to shut down before 2030.
However, the actual timing of its retirement is unknown and it is possible the site could be replaced
with gas-fired generation.
22
5.0 Regional outlooks
AESO 2016 Long-term Outlook
TABLE 5: South Region Load and Generation Capacity Forecast
Existing
(MW)
2022
(MW)
2027
(MW)
2030
(MW)
2037
(MW)
1,421
1,623
1,731
1,795
1,957
780
780
780
0
0
95
95
95
95
95
330
330
330
1,240
1,240
Simple-cycle
76
226
226
369
464
Hydroelectric
409
409
409
409
409
Wind
1,202
2,277
3,302
3,702
3,702
Other
42
42
42
42
42
2,934
4,159
5,184
5,857
5,952
Region Peak Load
Coal-fired
Cogeneration
Combined-cycle
Total Generation Capacity
Risks to Forecast
The main risks to load growth in the South Planning Region are related to overall economic and
population growth. As well, energy efficiency advancements or a blend of the two could result in
either higher or lower load growth compared to the Reference Case.
The main generation risks relate to the amount and location of renewables development. The South
Planning Region has attractive wind resources, and many projects have been initiated in the region
in recent history.
Other parts of the South Region, especially around the Medicine Hat area, show potential for
additional wind development. Finally, the South Region has the province’s best solar resources so
it is likely that future solar development would occur within this region.
Another generation risk in the South Planning Region is distribution-connected generation (DG)
development. There has been some interest already in building generation which is not directly
connected to the AIES. The pace, magnitude and ultimate potential of DG are presently uncertain.
CALGARY PLANNING REGION
Overview and Forecast
The Calgary Planning Region includes the City of Calgary, Airdrie and the surrounding area, and
accounts for about 33 per cent of the province’s total population. The region is characterized
primarily by urban load including significant residential and commercial demand as well as some
industrial load. In 2015, the region was summer-peaking; however, it has also been winter-peaking
in past years.
TABLE 6: Calgary Planning Region
2015 Average Load (MW)
1,195
2015 Summer Peak (MW)
1,732
2015/2016 Winter Peak (MW)
1,649
Population (000s)
1,356
Area (000km )
2
5.0 Regional outlooks
4
23
AESO 2016 Long-term Outlook
Load
The Calgary Planning Region represents 13 per cent of provincial load. Summer peak load growth
has been 2.2 per cent annually over the past 10 years while winter peak load growth has been
0.6 per cent. The Reference Case assumes summer and winter peak will grow at 1.4 per cent
and 1.6 per cent respectively to 2037 due to population growth and associated commercial and
residential demand growth.
Generation
The Calgary Planning Region has seen a large increase in generation capacity over the last 10 years.
A single generating unit, the 873 MW gas-fired combined-cycle Shepard Energy Centre, accounts
for the bulk of the new capacity additions. Currently, the region contains 1,470 MW of
gas-fired generation capacity.
Future generation potential in the region is related to technologies that can be implemented in an
urban landscape. This includes gas-fired technologies such as combined-cycle, simple-cycle,
combined-heat-and-power, and distribution-connected generation sources including microgeneration capacity such as rooftop solar panels.
The forecast for the region contains relatively small amounts of gas-fired generation capacity
additions over the forecast period.
TABLE 7: Calgary Region Load and Generation Capacity Forecast
Existing
(MW)
2022
(MW)
2027
(MW)
2030
(MW)
2037
(MW)
1,732
1,948
2,094
2,172
2,356
0
0
0
0
0
12
12
12
12
12
1,313
1,313
1,313
1,313
1,313
Simple-cycle
144
144
287
477
477
Hydroelectric
0
0
0
0
0
Wind
0
0
0
0
0
Other
0
0
0
0
0
1,469
1,469
1,612
1,802
1,802
Region Peak Load
Coal-fired
Cogeneration
Combined-cycle
Total Generation Capacity
Risks to Forecast
Risk to the load-growth forecast for the Calgary Planning Region is similar to that of the overall
province and relates to uncertainty around a recovery in crude oil prices, economic recovery,
and overall economic and population growth. An additional uncertainty regarding load growth is
energy efficiency, which has the potential to reduce demand in Calgary. Also, micro-generation
development such as rooftop solar has the potential to reduce demand perceived from an AIES-level
even though load isn’t actually reduced. Adoption of electric vehicles has the potential to add load in
Calgary depending on adoption rates, driving patterns, vehicle technology, and charging technology
and rules.
From a generation perspective, there has been generation proposed that could add non-intermittent
supply in the Calgary Planning Region. However, the timing of any such project is dependent on
developer decisions. The City of Calgary and surrounding areas also have the potential to add smallscale and micro-generation, but timing and magnitude of that development are uncertain.
24
5.0 Regional outlooks
AESO 2016 Long-term Outlook
CENTRAL PLANNING REGION
Overview and Forecast
The Central Planning Region spans the province east–west between the borders of B.C. and
Saskatchewan, and north–south between Cold Lake and Calgary. Its major population centres
are the cities of Red Deer and Lloydminster. The region represents about 11 per cent of Alberta’s
population, primarily concentrated in the Red Deer area.
The Red Deer area contains notable amounts of manufacturing, and there is significant oilsands
development in the Cold Lake area. The Central Planning Region also features a considerable
amount of pipelines, particularly in the eastern portion of the region.
TABLE 8: Central Planning Region
2015 Average Load (MW)
1,672
2015 Summer Peak (MW)
1,805
2015/2016 Winter Peak (MW)
2,036
Population (000s)
443
Area (000km )
146
2
Load
The Central Planning Region currently represents 18 per cent of Alberta’s load. Over the past 10 years,
the regional winter peak has grown by an average annual rate of 1.6 per cent. The Reference Case
assumes winter peak load will grow by 1.5 per cent annually by 2037 as a result of increasing pipeline
load, industrial and oilsands growth, and urban growth in the Red Deer area.
The Central Planning Region contains proposals for major export pipelines. It is presently unknown if
and when these pipelines will be approved and built. The Reference Case assumes one will be built
over the forecast horizon. However, it is possible that ultimately more than one or none at all will be built.
Generation
Over the past 10 years, the Central Planning Region has seen significant growth in wind-power and
gas-fired cogeneration capacity. In that timeframe, wind-power capacity in the region has increased
from no capacity to over 260 MW. Cogeneration in the region has also advanced with almost 300
MW developing. In addition to the wind and gas-fired generation, there have been small increases in
hydroelectric and coal-fired capacity. The generation capacity in the region is approximately 2,600
MW.
Generation potential in the region consists of a variety of generation technologies. Technologies that
could develop could include gas-fired generation, cogeneration, combined-cycle and simple-cycle,
and renewable power including wind, solar, hydroelectric, and biomass.
The forecast for the Central Planning Region assumes the development of gas-fired and wind-power
capacity. In both the near term and long term, wind generation is assumed to be a major source
of capacity increase. Wind capacity within the forecast was allocated across regions based on
the regional distribution of projects within the AESO connection process. Gas-fired developments
are primarily related to the retirement of coal-fired generation. As coal-fired units retire, baseload
combined-cycle generation would be able to utilize the existing infrastructure to meet future
electricity demand.
5.0 Regional outlooks
25
AESO 2016 Long-term Outlook
TABLE 9: Central Region Load and Generation Capacity Forecast
Existing
(MW)
2022
(MW)
2027
(MW)
2030
(MW)
2037
(MW)
2,036
2,415
2,550
2,622
2,805
689
540
385
0
0
1,129
1,129
1,129
1,129
1,129
Combined-cycle
0
0
0
455
455
Simple-cycle
0
5
5
148
243
Hydroelectric
485
485
485
485
485
Wind
261
836
1,361
1,561
1,561
Other
61
61
61
61
61
2,625
3,056
3,426
3,839
3,934
Region Peak Load
Coal-fired
Cogeneration
Total Generation Capacity
Risks to Forecast
Central Planning Region load risks include overall economic and population growth uncertainty and,
in particular, pipeline development. In addition to major export pipelines, intra-provincial pipeline
development is also a driver of load growth in the Central Planning Region, which is dependent on
oilsands development and the need to move crude oil and other liquids within the province.
The two main risks to generation development in the Central Planning Region are potential wind
generation development and coal-fired generation retirement and replacement. Currently, the
eastern half of this region in particular has a high potential for wind development. However, the
amount of wind power developed in the region will depend on renewables support and other factors.
Because of the size of the Central Planning Region, there is ultimately high potential overall for windpower development.
There is also a coal-fired facility in the Central Planning Region. Under announced provincial climate
change policy and current federal regulations, the facility will be required to shut down before
2030. However, the actual timing of its retirement is unknown and it is possible the facility could be
replaced with gas-fired generation.
NORTHWEST PLANNING REGION
Overview and Forecast
The Northwest Planning Region represents approximately one-third of the province and less than
7 per cent of the population. The largest population centre is the City of Grande Prairie. Given its low
population, residential and commercial electricity demand is relatively low compared to northwest
industrial demand, especially when compared to residential and commercial demand in other
regions. Some agricultural activity takes place in this region as well.
TABLE 10: Northwest Planning Region 26
2015 Average Load (MW)
1,035
2015 Summer Peak (MW)
1,125
2015/2016 Winter Peak (MW)
1,191
Population (000s)
280
Area (000km 2)
230
5.0 Regional outlooks
AESO 2016 Long-term Outlook
Load
The Northwest Planning Region accounts for approximately 11 per cent of the provincial total,
most of which is industrial. Load growth in the Northwest Planning Region has been one of the
slowest of any region over the past 10 years, with an average annual winter-peak load growth rate
of 0.6 per cent. The Reference Case assumes relatively strong winter-peak growth of 1.9 per cent
to 2037 due to significant increases in demand relating to unconventional oil and gas development
throughout the region.
Generation
The Northwest Planning Region has seen a significant increase in gas-fired and biomass generation
capacity over the last 10 years. Gas-fired additions have included multiple smaller peaking and
industrial facilities. These facilities have added over 300 MW of new generation capacity to the
system. In addition to gas-fired generation, biomass and waste-heat facilities have developed,
adding approximately 120 MW of capacity. The Northwest Planning Region currently contains
coal-fired, gas-fired, and biomass capacity totaling over 1,050 MW.
There is a variety of resources showing development potential in this region. Generation
development could occur from gas-fired generation, hydroelectricity, wind-power, and biomass
power. Gas-fired generation in the region could be related to industrial activity, or a need for
additional non-intermittent generation on the overall system, and the use of brownfield sites. In the
northwest, there are a variety of locations that could be suitable for hydroelectric generation and a
potential for biomass generation development exists. A small amount of wind-power capacity has
also been identified in the region.
The majority of forecast generation in the Northwest Planning Region is from gas-fired facilities.
Large gas-fired additions are related to the retirement of coal-fired capacity. Small amounts of
other generation, including wind, have been assumed in the forecast. Wind capacity within the
forecast was allocated across regions based on the regional distribution of projects within the AESO
connection process.
TABLE 11: Northwest Region Load and Generation Capacity Forecast
Existing
(MW)
2022
(MW)
2027
(MW)
2030
(MW)
2037
(MW)
1,191
1,506
1,586
1,653
1,802
Coal-fired
144
0
0
0
0
Cogeneration
147
147
147
147
147
73
73
73
528
528
Simple-cycle
526
648
648
791
981
Hydroelectric
0
0
0
0
0
Wind
0
100
300
400
400
Other
176
217
217
217
217
1,066
1,185
1,385
2,083
2,273
Region Peak Load
Combined-cycle
Total Generation Capacity
Risks to Forecast
The main source of load growth risk in the Northwest Planning Region relates to unconventional oil
and gas development. In the past two years, there has been a significant amount of load projects
that have applied to the AESO—in the Fox Creek and Grande Cache areas for example. The timing
and ultimate potential of load growth due to unconventional oil and gas development remains
uncertain, especially given current low crude oil and natural gas prices. The Northwest Planning
Region also has potential for oilsands growth.
5.0 Regional outlooks
27
AESO 2016 Long-term Outlook
There are a number of generation risks in the Northwest Planning Region. Similar to load, this region
has potential for oilsands cogeneration development. Any oilsands development could lead to
associated cogeneration capacity.
There has also been combined-cycle generation proposed in the Northwest Planning Region, but its
timing and ultimate potential is unknown. Numerous biomass and simple-cycle facilities have been
built in this region as well, and it has potential for more.
NORTHEAST PLANNING REGION
Overview and Forecast
The Northeast Planning Region is sparsely populated, containing approximately six per cent of
the provincial population. Most residents are located in the Fort McMurray area of the Regional
Municipality of Wood Buffalo. The economy in this region is driven by the oilsands industry and
is directly linked to future oilsands projects. The low population in this planning region results in
minimal residential and commercial load.
TABLE 12: Northeast Planning Region
2015 Average Load (MW)
2,404
2015 Summer Peak (MW)
2,683
2015/2016 Winter Peak (MW)
2,947
Population (000s)
248
Area (000km 2)
169
Load
Despite the low population, the Northeast Planning Region contains about 26 per cent of AIL. Over
the past 10 years, load growth has been the strongest of any region with a winter peak growth rate
of 5.2 per cent annually as oilsands projects developed and ramped up production. In the near term,
projects currently under construction are expected to contribute to load growth. To 2027, average
annual winter peak load growth is forecast at 2.7 per cent. In the longer run, the Reference Case
forecasts average annual winter-peak load growth at a rate of 2.0 per cent to 2037.
Over time, new oilsands projects are expected to develop, and increased related pipeline load is also
expected to contribute to load growth. Due to the ramp-up of oilsands and other industrial projects,
the Northeast Planning Region is Alberta’s fastest growing planning region in terms of load with
almost 1,600 MW of new load expected by 2037.
Generation
Over the last 10 years, the Northeast Planning Region has seen the largest amount of generation
capacity growth compared with any other planning region. Over 1,300 MW of cogeneration has
been developed, related to the expansion of the oilsands. A small amount of biomass has also
developed. The region currently has over 3,200 MW of generation capacity.
Potential development of generation in the region is primarily related to oilsands growth, which is
well suited to cogeneration. In addition to gas-fired cogeneration, both combined-cycle and simplecycle generation capacity has been proposed in the region. Other technologies that could develop
include biomass and hydroelectric.
28
5.0 Regional outlooks
AESO 2016 Long-term Outlook
The forecast for the region consists of large amounts of gas-fired generation. This includes a mix
of cogeneration, combined-cycle and simple-cycle generation. The development of each technology
is related to its specific driver. Cogeneration is related to industrial and oilsands growth in the region.
Combined-cycle and simple-cycle are related to overall growth in system demand and coal-fired
retirements.
TABLE 13: Northeast Region Load and Generation Capacity Forecast
Existing
(MW)
2022
(MW)
2027
(MW)
2030
(MW)
2037
(MW)
2,947
3,708
4,059
4,197
4,511
0
0
0
0
0
3,080
3,888
3,941
4,083
4,225
Combined-cycle
0
0
970
970
1,425
Simple-cycle
0
215
215
263
358
Hydroelectric
0
0
0
0
0
Wind
0
0
0
0
0
Other
149
149
149
149
149
3,229
4,252
5,275
5,465
6,157
Region Peak Load
Coal-fired
Cogeneration
Total Generation Capacity
Risks to Forecast
Since the bulk of Northeast Region load growth is related to oilsands development, the main source
of load forecast risk is directly related to the pace and magnitude of oilsands development which
could vary depending on the future attractiveness of oilsands development. Factors which affect this
attractiveness include future crude oil prices, project costs, export infrastructure, policy shifts and
support, and financing/capital availability.
This uncertainty is exacerbated by the potential for electricity-based oilsands extraction technologies
which could potentially complement or replace other forms of extraction and which are likely to use
significantly higher amounts of electricity. Load related to pipeline development to ship oilsands
crude oil to market is also dependent on the amount of future oilsands development. This region
also contains the Fort Saskatchewan area, which has potential for additional industrial development
that could affect regional load.
The Northeast Planning Region’s generation is mostly made up of cogeneration, the future of
which is tied to oilsands development. Fewer oilsands projects would result in less cogeneration
development and vice versa. Cogeneration development is also dependent on the decisions of
oilsands developers, which are based on numerous factors that could be impacted by economic
recovery and the CLP.
The Northeast Planning Region also has the potential for large-scale hydroelectric development.
While the Reference Case does not assume hydroelectric development will occur, it is possible that
it could develop; however, due to the extensive regulatory process to approve hydroelectric facilities
as well as long construction times, new hydroelectric generation is unlikely to develop in less than
10 years.
5.0 Regional outlooks
29
AESO 2016 Long-term Outlook
EDMONTON PLANNING REGION
Overview and Forecast
The Edmonton Planning Region contains the City of Edmonton, St. Albert, Sherwood Park, Spruce
Grove, Leduc and the Wabamun Lake area. It represents approximately 33 per cent of Alberta’s
population. This region contains the most significant amount of provincial generation capacity,
specifically in the Wabamun area.
TABLE 14: Edmonton Planning Region
2015 Average Load (MW)
1,564
2015 Summer Peak (MW)
2,141
2015/2016 Winter Peak (MW)
2,082
Population (000s)
1,358
Area (000km 2)
22
Load
This region represents 17 per cent of Alberta’s load, and over the past 10 years has seen its summer
peak grow at an average annual rate of 2.2 per cent, and its winter peak grow at 1.1 per cent. While
load is primarily residential and commercial, there is also significant oil refining, manufacturing and
pipeline load.
By 2037 winter-peak load is forecast to grow at 1.9 per cent annually. The bulk of this growth
is expected in the City of Edmonton area, driven primarily by residential, commercial and
industrial development.
Generation
The Edmonton Planning Region currently contains the largest amount of generation capacity
compared to any other planning region. While in the last 10 years it has seen almost 500 MW of
retirements, it has also seen a gross increase of over 900 MW in generation capacity. In the last
10 years there has been approximately 680 MW of coal-fired capacity increases and 250 MW of
gas-fired additions. The region currently has over 4,900 MW of generation capacity.
Potential development in the region is primarily gas-fired generation including gas-fired technologies
such as combined-cycle, simple-cycle, and combined heat and power. The region contains aging
coal-fired generation capacity whose brownfield sites and infrastructure could be used to support
new gas-fired generation. This replacement of coal-fired capacity with gas-fired capacity represents
the largest potential of new capacity in the future.
The forecast for generation in the region consists of large amounts of gas-fired generation with
timing related to the retirement of coal-fired units and increases in AIL.
30
5.0 Regional outlooks
AESO 2016 Long-term Outlook
TABLE 15: Edmonton Region Load and Generation Capacity Forecast
Existing
(MW)
2022
(MW)
2027
(MW)
2030
(MW)
2037
(MW)
Region Peak Load
2,141
2,575
2,753
2,857
3,127
Coal-fired
4,676
4,100
3,326
0
0
39
82
82
82
82
0
910
1,760
4,035
4,490
Simple-cycle
250
261
261
261
356
Hydroelectric
0
0
0
0
0
Wind
0
0
0
0
0
Other
0
0
0
0
0
4,965
5,353
5,429
4,378
4,928
Cogeneration
Combined-cycle
Total Generation Capacity
Risks to Forecast
Similar to the Calgary Planning Region, the main risk to load growth in the Edmonton Planning
Region relates to overall provincial economic and population growth as well as energy efficiency
and micro-generation development. Material changes in any of these could impact the outlook for
future load growth in the region. Also, micro-generation development such as rooftop solar has the
potential to reduce demand perceived from an AIES-level even though load isn’t actually reduced.
Adoption of electric vehicles has the potential to add load in Edmonton depending on adoption
rates, driving patterns, vehicle technology, and charging technology and rules.
The Edmonton Planning Region contains the bulk of Alberta’s coal-fired generation units with
significant uncertainties surrounding the timing of coal-fired generation retirement. It is unclear at the
time of the 2016 LTO’s publication what the pace of retirement will be.
Several combined-cycle gas generation facilities have been proposed in the Edmonton area
including some at brownfield coal sites. Brownfield coal sites offer advantages over greenfield sites,
including cost and connection capacity to the AIES. Despite these cost advantages, there is no
guarantee future natural gas generation will develop at existing coal sites and the full potential for
gas-fired generation development in the region is unclear.
6.0 Appendix
31
AESO 2016 Long-term Outlook
Appendix A
SUPPLEMENTAL INFORMATION
Load and generation data related to the AESO’s Reference Case and scenarios are available to
market participants and the general public. They can be found online in the 2016 LTO Data File at
www.aeso.ca/2016lto
COAL RETIREMENT DATE ASSUMPTIONS
Table 16 shows the commissioning dates of Alberta coal-fired units, their federal end-of-useful-life
dates, and the assumed retirement dates in the 2016 LTO Reference Case and Alternate-policy
Scenario. Section 3.0 expands upon the rationale for those assumptions.
TABLE 16: Coal retirement date assumptions
32
Asset
Year of
Commissioning
End-of-UsefulLife Under
Federal Coal
Regulations
Reference Case
Retirement Date
Assumptions
Alternatepolicy Scenario
Retirement Date
Assumptions
Battle River #3 (BR3)
1969
Dec. 31, 2019
Dec. 31, 2019
Dec. 31, 2019
Sundance #1 (SD1)
1970
Dec. 31, 2019
Dec. 31, 2019
Dec. 31, 2019
H.R. Milner (HRM)
1972
Dec. 31, 2019
Dec. 31, 2019
Dec. 31, 2019
Sundance #2 (SD2)
1973
Dec. 31, 2019
Dec. 31, 2019
Dec. 31, 2019
Battle River #4 (BR4)
1975
Dec. 31, 2025
Dec. 31, 2025
Dec. 31, 2019
Sundance #3 (SD3)
1976
Dec. 31, 2026
Dec. 31, 2026
Dec. 31, 2020
Sundance #4 (SD4)
1977
Dec. 31, 2027
Dec. 31, 2026
Dec. 31, 2020
Sundance #5 (SD5)
1978
Dec. 31, 2028
Dec. 31, 2027
Dec. 31, 2020
Sundance #6 (SD6)
1980
Dec. 31, 2029
Dec. 31, 2028
Dec. 31, 2020
Battle River #5 (BR5)
1981
Dec. 31, 2029
Dec. 31, 2028
Dec. 31, 2021
Keephills #1 (KH1)
1983
Dec. 31, 2029
Dec. 31, 2028
Dec. 31, 2023
Keephills #2 (KH2)
1984
Dec. 31, 2029
Dec. 31, 2028
Dec. 31, 2024
Sheerness #1 (SH1)
1986
Dec. 31, 2036
Dec. 31, 2027
Dec. 31, 2026
Genesee #2 (GN2)
1989
Dec. 31, 2039
Dec. 31, 2027
Dec. 31, 2026
Sheerness #2 (SH2)
1990
Dec. 31, 2040
Dec. 31, 2027
Dec. 31, 2027
Genesee #1 (GN1)
1994
Dec. 31, 2044
Dec. 31, 2029
Dec. 31, 2028
Genesee #3 (GN3)
2005
Dec. 31, 2055
Dec. 31, 2029
Dec. 31, 2029
Keephills #3 (KH3)
2011
Dec. 31, 2061
Dec. 31, 2029
Dec. 31, 2029
Glossary of terms
AESO 2016 Long-term Outlook
Appendix B
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 17.
More information regarding Alberta Reliability Standards can be found on the AESO website.15
Under MOD-016-AB-1.116,62 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 2016 LTO publication is that documentation. In accordance
with MOD-016-AB-1.1, the 2016 LTO is published and distributed within 30 calendar days of a revision
being approved by the AESO.
Under MOD-017-AB-0.117, the AESO is required to report to the Western Electricity Coordinating Council
(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 2016 LTO data file.
Under MOD-018-AB-018, 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.
TABLE 17: Reliability Requirements – Documentation and Reporting Standards
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
Forecast of Interruptible Demands Data
LOAD FORECAST REPORTING TO WECC
For compliance to the related standards as described above as well as reporting requirements to the
WECC, AESO load forecasts are described in the following terms:
A)
B)
C)
D)
Alberta Internal Load (AIL)
Behind-the-Fence (BTF) is classified as Non-reserved Demand
Demand Opportunity Service and Load Shed Service – Imports (LSSi) are classified as Non-firm Demand
Load that is not classified as either non-reserved or non-firm is classified as: Firm Peak Demand such that A=B+C+D
A
ALBERTA INTERNAL LOAD
(AIL)
B
C
D
NON-RESERVE DEMAND
(e.g. BTF DEMAND)
NON-FIRM DEMAND
(e.g. DOS, LSSi)
FIRM PEAK DEMAND
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www.aeso.ca/rulesprocedures/17006.html
16
www.aeso.ca/rulesprocedures/22088.html
17
www.aeso.ca/rulesprocedures/22090.html
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www.aeso.ca/rulesprocedures/22091.html
Glossary of terms
33
AESO 2016 Long-term Outlook
Glossary of terms
Alberta Interconnected Electric System (AIES): The system of interconnected transmission
power lines and generators in Alberta.
Alberta Internal Load (AIL): The total electricity consumption within the province of Alberta
including behind-the-fence (BTF) load, the City of Medicine Hat and losses (transmission
and distribution).
Baseload generation: Generation capacity normally operated to serve load on an around-theclock basis.
Behind-the-fence load (BTF): Industrial load served in whole, or in part, by onsite generation built
on the host’s site.
Biomass: Organic matter that is used to produce synthetic fuels or is burned in its natural state
to produce energy. Biomass fuels include wood waste, peat, manure, grain by-products and food
processing wastes.
Brownfield: Land previously or currently used for industrial or certain commercial purposes.
Bulk transmission system: The integrated system of transmission lines and substations that
delivers electric power from major generating stations to load centres. The bulk system, which
generally includes 500 kilovolt (kV) and 240 kV transmission lines and substations, also delivers/
receives power to and from adjacent control areas.
Capability: The maximum load that a generating unit, generating station or other electrical
apparatus can carry under specified conditions for a given time period without exceeding limits of
temperature and stress.
Carbon offset: A financial instrument representing a reduction in greenhouse gas (GHG) emissions.
Cooling Degree Day (CDD): The number of degrees that a day’s average temperature is above a
threshold temperature.
Cogeneration: The simultaneous production of electricity and another form of useful thermal energy
used for industrial, commercial, heating or cooling purposes.
Combined-cycle: A system in which a gas turbine generates electricity and the waste heat is used
to create steam to generate additional electricity using a steam turbine.
Demand (electric): The volume of electric energy delivered to or by a system, part of a system, or
piece of equipment at a given instant or averaged over any designated period of time.
Demand-side management: Activities that occur on the demand (customer) side of the meter and
are implemented by the customer directly or by load-serving entities.
Dispatch: The process by which a system operator directs the real-time operation of a supplier or a
purchaser to cause a specified amount of electric energy to be provided to, or taken off, the system.
Distribution-connected generation: Small-scale power sources typically connected to a
distribution system at customer locations.
Emission intensity: The ratio of a specific emission (such as carbon dioxide) to a measure of
energy output. For the electricity sector, emission intensity is usually expressed as emissions per
megawatt hour (MWh) of electricity generated.
Gas turbine: See simple-cycle.
34
Glossary of terms
AESO 2016 Long-term Outlook
Generating unit: Any combination of an electrical generator physically connected to reactor(s),
boiler(s), combustion or wind turbine(s) or other prime mover(s) and operated together to produce
electric power.
Geothermal energy: Where the prime mover is a turbine driven either by steam produced from
hot water or by natural steam that derives its energy from heat found in rocks or fluids beneath the
surface of the Earth.
Gigawatt (GW): One billion watts.
Gigawatt hour (GWh): One billion watt hours.
Greenfield: Land being considered for development that has not previously been used for
commercial or industrial purposes.
Greenhouse gas (GHG) emissions: Gases that trap the heat of the sun in the Earth’s atmosphere,
producing a greenhouse effect.
Grid: A system of interconnected power lines and generators that is operated as a unified whole to
supply customers at various locations. Also known as a transmission system.
Heating Degree Day (HDD): The number of degrees that a day’s average temperature is below a
threshold temperature.
Independent system operator (ISO): A system and market operator that is independent of other
market interests. In Alberta the entity that fulfils this role is the Alberta Electric System Operator.
Intertie: A transmission facility or facilities, usually transmission lines, that interconnect two adjacent
control areas.
Load (electric): The electric power used by devices connected to an electric system.
Load factor: A measure of the average load, in kilowatts, supplied during a given period. It is
generally used to determine the total amount of energy that would have been used if a given
customer’s maximum load was sustained over an extended time period and, through comparison,
show what percentage of potential load was actually used.
Megawatt (MW): One million watts.
Megawatt hour (MWh): One million watt hours.
Offset: See carbon offset.
Operating reserve: Generating capacity that is held in reserve for system operations and can be
brought online within a short period of time to respond to a contingency. Operating reserve may be
provided by generation that is already online (synchronized) and loaded to less than its maximum
output and is available to serve customer demand almost immediately. Operating reserve may also
be provided by interruptible load.
Peak load/demand: The maximum power demand (load) registered by a customer or a group
of customers or a system in a stated time period. The value may be the maximum instantaneous
load or, more usually, the average load over a designated interval of time such as one hour, and is
normally stated in kilowatts or megawatts.
Peaking capacity: The capacity of generating equipment normally reserved for operation during
hours of the highest daily, weekly, or seasonal loads. Some generating equipment may be operated
at certain times as peaking capacity, and at other times to serve loads on an around-the-clock basis.
Point-of-delivery (POD): Point(s) for interconnection on the transmission facility owner’s (TFO)
system where capacity and/or energy is made available to the end-use customer.
Reserve margin: The percentage of installed capacity exceeding the expected peak demand during
a specified period.
Glossary of terms
35
AESO 2016 Long-term Outlook
Simple-cycle: Where a gas turbine is the prime mover in a plant. A gas turbine consisting typically
of one or more combustion chambers where liquid or gaseous fuel is burned. The hot gases are
passed to the turbine where they expand, driving the turbine that in turn drives the generator.
Solar (power): A process that produces electricity by converting solar radiation into electricity or
to thermal energy to produce steam to drive a turbine.
Tariff (Transmission): The terms and conditions under which transmission services are provided,
including the rates or charges that users must pay.
Transmission: The transfer of electricity over a group of interconnected lines and associated
equipment, between points of supply and points at which it is transformed for delivery to
consumers, or is delivered to other electric systems.
Transmission system (electric): An interconnected group of electric transmission lines and
associated equipment for moving or transferring electricity in bulk between points of supply and
points at which it is transformed for delivery over the distribution system lines to consumers, or is
delivered to other electric systems.
Watt: The unit of power equal to one joule of energy per second. It measures a rate of energy
conversion. A typical household incandescent light bulb uses electrical energy at a rate of
25 to 100 watts.
Watt hour (Wh): An electrical energy unit of measure equal to one watt of power supplied to or
taken from an electric circuit steadily for one hour.
36
Glossary of terms
This document complements the AESO’s existing publications and supports our commitment to
sharing information with market participants, other stakeholders and all Albertans in a timely, open
and transparent manner. Readers are invited to provide comments or suggestions for future reports.
For more information, or to provide feedback, contact [email protected]
Alberta Electric System Operator
2500, 330-5th Avenue SW
Calgary, AB T2P 0L4
Phone: 403-539-2450
Fax: 403-539-2949
www.aeso.ca
www.poweringalberta.ca
@theaeso
REV 06/16