Download Can the Electricity Market Structure Accommodate Significant Levels of

Can the Electricity Market Structure
Accommodate Significant Levels of
Renewable Generation? An
Evaluation of Carbon Policy Options
for the Alberta Electricity Sector
Prepared for:
Alberta Market Surveillance
Administrator
Brian Rivard
Adonis Yatchew
October 3, 2015
DISCLAIMER
The views expressed herein are the views and opinions of the authors and do not reflect or
represent the views of Charles River Associates or any of the organizations with which the authors
are affiliated. Any opinion expressed herein shall not amount to any form of guarantee that the
authors or Charles River Associates has determined or predicted future events or circumstances,
and no such reliance may be inferred or implied. The authors and Charles River Associates accept
no duty of care or liability of any kind whatsoever to any party, and no responsibility for damages,
if any, suffered by any party as a result of decisions made, or not made, or actions taken, or not
taken, based on this paper.
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Table of Contents
Executive Summary ......................................................................................................................... 3
1.
Introduction and Overview ..................................................................................................... 5
2.
Carbon Policy Options for the Electricity Sector ..................................................................... 6
2.1
Market-Based Incentive Policies ......................................................................................... 6
2.1.1
Cap-and-Trade System .................................................................................................... 6
2.1.2
Carbon Tax System .......................................................................................................... 7
2.1.3
Renewable Generation Tax Credits ................................................................................. 8
2.2
Long-Term Contracting Options .......................................................................................... 8
2.2.1
Feed-in-Tariff Programs................................................................................................... 8
2.2.2
Competitively Tendered Renewable Procurement Programs......................................... 9
2.3
3.
Renewable Portfolio Standards ........................................................................................... 9
The Alberta Electricity Market and the Implications of Significant Amounts of Renewables10
3.1
Overview of the Alberta Electricity Market and its Objectives ......................................... 10
3.2
The Effect of Renewables on Electricity Markets .............................................................. 12
3.3
Possible Modifications to the Market to Accommodate Large Scale Renewables ........... 15
3.4
The Ontario Experience: A transition from an energy-only market to a “hybrid” market 18
3.5
Potential Impacts of Alternative Options on the Alberta Electricity Market .................... 23
4.
Policy Evaluation of Options .................................................................................................. 25
5.
Concluding Comments .......................................................................................................... 29
APPENDIX: Biographies ................................................................................................................. 31
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Executive Summary

A reasonably priced and reliable supply of electricity is an important contributor to
Alberta's economic health, particularly at a time when oil and natural gas prices are low
and economic diversification may be a Provincial strategy. Perhaps more than any other
jurisdiction, the Alberta electricity market relies on competition and energy price signals
to encourage efficient generation investment and innovative technology choice. The
Alberta electricity market needs to continue to function effectively to incentivize these
outcomes.

Alberta has invested in an energy-only electricity market that has served the Province
well for more than a decade. Electricity has been reliably supplied in competitive
markets. Abandonment of the market model would result in substantial loss in value for
the people of Alberta.

The Alberta energy-only market can continue to function effectively with additions of
considerable amounts of renewable generation. While an expansion of renewable
energy sources like wind and solar, could introduce new market dynamics, Alberta’s
competitive market can adapt to efficiently accommodate these new additions. Its
continued effectiveness depends very substantially on the specific carbon policy that is
introduced, the pace at which it is implemented and the clarity and stability of
government policy.

The empirical and historical evidence supports the judicious adaptation of markets to
correct their limitations or imperfections, rather than the replacement of markets with
bureaucratic and technocratic processes. A return to a highly regulated, centrally
planned framework is likely to lead to loss of investor confidence, substantial increases
in regulatory burden and higher electricity prices in the long term. Furthermore, a large
share of risk would be transferred from firms to customers.

By implementing well-designed market mechanisms to mitigate climate change, the
overall costs of achieving these objectives would be minimized; alternatively the
environmental gains for a given level of expenditure would be maximized. As far as
possible, market mechanisms should be technologically neutral and agnostic with
respect to the scale of an individual installation.

Several suitable market based mechanisms could be considered, most prominent among
these are cap-and-trade and carbon taxes. These are the most compatible with the
principles of the Alberta electricity market. Cap-and-trade has two important
advantages. First, it directly targets total emissions. Second, its burden tends to
automatically adjust during periods of slow growth as one would expect the unit price of
emissions to decline. In contrast, a per-unit carbon tax is generally seen to be fixed over
the course of the business cycle.

Renewable portfolio standards are an alternative mechanism which is generally
compatible with the Alberta electricity market and an investor-owned generation
system, particularly when combined with tradeable green energy certificates. In this
case each generator is required to produce or acquire a certain proportion of its supply
3
from renewable sources.

All three of these mechanisms – cap-and-trade, carbon taxes and renewable portfolio
standards – are technologically neutral in the sense that firms and individuals select the
technology that best suits their circumstances. The devolution of technological choice
to the market-place provides stronger incentives for cost-effective innovation.

Long term contracts for specific renewable technologies, are the least compatible with
the principles of the Alberta electricity market. Overlaying government-backed
administered contracts would fundamentally alter the character of the Alberta electricity
market in ways that would be difficult to reverse. These include feed-in-tariff programs
and green power calls, which typically require government agencies to make technology
choices. Such programs may be less effective at delivering a specific carbon reduction
goal because they constitute a subsidy to renewables, rather than a cost associated with
carbon production. Increased renewable production does not necessarily displace
carbon based generation. In Ontario, for example, at certain times wind energy has
displaced hydraulic or even nuclear supply.

In order to provide for an effective transition it is essential that a clear policy position be
taken, ideally one that expresses continued support for an electricity market with a
suitable and orderly incorporation of incentives for decarbonization. In the absence of a
clear commitment by the Government to preserve the market structure, there is likely
to be reluctance on the part of investors to undertake the required risks.
4
1. Introduction and Overview
The Alberta government has tasked an Advisory Panel on climate change with the responsibility
of reviewing Alberta’s current suite of policies, engaging with Albertans, and providing the
Government with advice on a comprehensive set of measures to reduce greenhouse gas
emissions (“GHG”).1 The Advisory Panel will consider a variety of GHG policy alternatives
including carbon pricing approaches such as a carbon tax system and a cap-and-trade system;
performance standard approaches; and Alberta’s current system which is a hybrid of a carbon
pricing system and a performance standard.2
The electricity sector is the second largest contributor to overall GHG emissions in Alberta,
although its share, which was 17% in 2013, is relatively modest.3 Currently, the electricity sector
in Alberta is deregulated. The Alberta Electricity System Operator (“AESO”) operates an energyonly wholesale market in which electricity production and investment decisions are made by
private companies which receive a market price determined by supply and demand. These
entities bear the risks associated with their decisions. This is in contrast to other jurisdictions
where such decisions are often made by government or an agency of the government, with risks
being borne by electricity consumers through electricity rates.
The Advisory Panel will consider which GHG policy is most appropriate for the electricity sector.
Depending on the approach or the specific GHG reduction targets that are adopted, there is the
potential for large scale deployment of renewable generation. The Alberta Market Surveillance
Administrator (“MSA”) has asked Charles River Associates to consider how the current Alberta
electricity market structure could accommodate significant amounts of renewable generation.
Specifically, we have been asked to consider whether and how the wholesale electricity market
can continue to function fairly, efficiently and in an openly competitive manner under different
GHG policies and with significant amounts of renewable generation.
There are several carbon policy options that could be adopted in the electricity sector. For the
purposes of this report, we focus on three types: (i) market-based mechanisms such as a ‘capand-trade’ system or a ‘carbon tax’; (ii) long-term contracting of renewables through ‘feed-intariffs’ or ‘green power calls’; and; (iii) ‘renewable portfolio standards’ systems. We consider
how each option could be implemented within the electricity sector; provide a qualitative
assessment of the effects the policy would have on electricity prices, GHG reductions and
renewable generation deployment; and evaluate the policy relative to a standard set of criteria.
The report proceeds as follows. Section 2 considers carbon policy options for the electricity
sector. Section 3 examines the current Alberta electricity market and the implications for its
continued sustainability under alternative carbon mitigation approaches. Section 3 also includes
a case study outlining the Ontario experience. Section 4 provides a broader analysis of policy
alternatives and evaluates them against standard criteria. Section 5 provides concluding
comments.
Climate Leadership Discussion Document, page 1.
Climate Leadership Discussion Document, page 18 identifies these three general approaches. The document also
identifies other approaches for the key sectors.
3
Climate Leadership Discussion Document, page 15, 45 Mt / 267 CO2e in 2013. In terms of sectors, the doughnut
chart at p. 14 of the same document puts electricity in 3rd place behind “Other oil and gas” at 24% and “Oil sands” at
22%.
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2
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2. Carbon Policy Options for the Electricity Sector
In this section we review three types of carbon policy options: (i) market-based incentive
policies; (ii) long-term contracting of renewable technologies; and (iii) renewable portfolio
standards systems.
2.1
Market-Based Incentive Policies
Market-based incentive policies are designed to address and correct a market failure (for
example, the damages and associated costs to society that GHG emissions cause through
climatic effects) by creating systems that cause the polluting entities and consumers to
incorporate the cost of the externality in their decision making. This can be accomplished
through the establishment of emission property rights and the creation of a market for the
trading of these rights, or by the direct imposition of a fee or tax. Three types of commonly
used market-based incentive policies are cap-and-trade systems, carbon taxes and renewable
generation tax credits. The first two increase the price of using carbon fuels, the third reduces
the relative cost of producing carbon-free energy, thus allowing it to compete more effectively.
2.1.1 Cap-and-Trade System
In a cap-and-trade system, the government establishes an overall cap on emissions from
covered sectors and a system of allowances, which give one-time permission to emit a fixed
quantity (e.g., a metric ton) of GHG. The initial cap is typically established relative to emissions
in a base-line period, and the annual caps presumably decline over time to achieve the
government’s emission reduction targets. Allowances are determined on an annual basis. They
can be distributed free-of-charge or sold through periodic auctions. The allocation of free
allowances is typically seen as a transitional practice to help emission intensive industries adapt
to the new compliance requirements and to reduce leakage risk (i.e., the risk that some covered
entities may leave the jurisdiction due to competitive disadvantage caused by the cap-and-trade
program). Covered emitting entities are required to meet compliance within a certain period
(e.g., within one or two years). Emitting entities can then buy, sell or bank allowances to manage
their individual circumstances.4 The government may also establish a system of offsets. An
offset is a credit for a verified emission reduction from a source outside the covered sectors.
Offsets can be used by covered entities to meet their cap-and-trade obligations instead of using
emission allowances or reducing on-site emissions.
By establishing an overall cap on emissions, cap-and-trade systems offer a high level of certainty
with respect to the total emissions released within a region. However, the price of emission
permits is less certain and depends on factors influencing the supply and demand of allowances.
Certain price stabilizing mechanisms such as price caps and price floors can be introduced but
these may reduce the effectiveness of the policy.
A strategic reserve of allowances can also be made available for sale at predetermined prices
during periods of extreme market circumstances. Access to the reserve may help to maintain a
4
Individuals or groups may even purchase allowances and simply allow them to expire, thereby in effect reducing the
overall emissions cap.
6
reliable supply of electricity. Relatedly, the interaction of electricity price controls such as
electricity price caps may need to be reconsidered to allow for the efficient pass-through of
carbon costs to electricity prices.
Finally, the government or its agencies must establish and administer reporting requirements
and third party verification systems with the potential for penalties for non-compliance. If
electricity can be imported from jurisdictions that are not under equivalent GHG regulation, a
border control program to ensure GHG compliance by imports may also be required.
Effects on Electricity Prices, GHG Emissions and Renewable Investment
The acquisition costs or value of permits would generally be reflected in the bids submitted to
the marketplace; one would expect a rise in wholesale electricity prices. As a result, electricity
consumers would make consumption decisions that incorporate the marginal cost of carbon;
this in turn would create further incentives for reduced consumption and hence emissions.
In theory, the increase in the offer prices of emitting generators can lead to a change in merit
order with non-emitting generators moving ahead of emitting generators. In practice however,
since most renewables typically have lower marginal cost than emitting generators already, this
effect is not likely to be material. The higher market prices will, however, provide more net
revenue to non-emitting renewable resources. This will act as a stimulus for investment in
renewables relative to emitting generation technologies. However, under the energy-only
market, this investment would have to be entirely through energy prices and the renewable
investor will have to take on the risk of the investment. Much of the evidence to date suggests
that renewables require some form of additional incentive.
2.1.2 Carbon Tax System
A carbon tax system levies a fee that is proportionate to the amount of carbon that is injected
into the atmosphere when a particular fuel is burned; for example, a tax on gasoline, jet fuel, or
coal burned in electricity generation stations. By applying a sufficiently high tax, users are
incentivized to reduce their use of carbon-based fuel and to switch to other sources of energy.
The tax does not target the quantity of GHG emissions directly, hence there is less certainty
around the level of emissions in a region from year to year than there is under cap-and-trade.
Policy makers may adjust the tax from time to time to achieve desired environmental outcomes.
Effects on Electricity Prices, GHG Emissions and Renewable Investment
Under a carbon tax, all emitting generators would be taxed on a per-ton basis which will in turn
influence prices. As with a cap-and-trade system, this would put upward pressure on electricity
prices. The effects on the merit order and renewable investments are likely to be similar to
those in a cap-and-trade regime.
One of the disadvantages of a tax approach is that the tax rate does not adjust automatically
over the course of the business cycle. Permits, on the other hand, are more likely to decline in
price during periods of weak economic growth, and to increase when the economy is strong.
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2.1.3 Renewable Generation Tax Credits
Renewable energy tax credits are designed to reduce costs borne by renewable producers,
whether they are corporations or homeowners. In some cases they are designed to reduce the
investment costs. In others, the producer receives a tax credit for each kWh of renewable
energy that is produced. The magnitude of the credit may vary by generation type. This
approach has met some success in promoting renewable production in the U.S.5
Design features can affect efficacy and efficiency. For example, some argue that tax credits
should be on production and not investment because it is production that may offset carbon
based supply. However, a simple volume-based production credit does not send locational
signals to developers. Volume-based production can also distort efficient dispatch when there is
a surplus of electricity from other “clean” energy generators. Finally, volume-based production
does not ensure that discretionary maintenance outages are taken at times when electricity
prices are low.6
Effects on Electricity Prices, GHG Emissions and Renewable Investment
Tax credits to specific renewable technologies will provide owners with an additional revenue
stream beyond the energy price. This tax credit may stimulate renewable investment and
additional output. The costs associated with the program will be borne by tax payers and will
not be captured in the energy price. Furthermore, the link between renewable production and
carbon reduction is indirect; for example, in some circumstances, the renewable energy that is
being produced may not displace carbon based supply.
2.2
Long-Term Contracting Options
In many jurisdictions, price supports through long-term contracts have been very effective at
promoting the rapid deployment of renewable energy technologies and the expansion of
renewable energy generation.7 Long-term contracts transfer price risk from suppliers to
consumers by providing a subsidy above prevailing market prices to preferred renewable
generation sources. Long-term contracts may come in the form of a feed-in-tariff or they may
be offered through a competitive renewable procurement program such as a ‘green power call’.
2.2.1 Feed-in-Tariff Programs
Feed-in-tariff programs fix the price for renewable energy and allow the quantity of renewable
energy to be determined through private investment decisions. Feed-in-tariff programs usually
5
In April of 2002, the Federal Government set up the Wind Power Production Incentive Program which provided a
financial incentive of about 1 cent per kilowatt-hour of wind energy produced from the installation of up to 1,000
megawatts (MW) of new wind power capacity in Canada by 2007. This program was replaced by the ecoENERGY for
Renewable Power program which was established to support renewable projects by providing some economic value
for their environmental benefits in the absence of any form of price on greenhouse gases that would allow the
market to play this role. The Federal Government discontinued the program in 2010.
6
See, e.g., The Future of Solar Energy, MIT Energy Initiative, 2015.
7
This has been the case in Denmark, Germany, Spain and Ontario. Long-term contracts are often used to promote a
variety of policy objectives including promoting environmental goals such as climate mitigation and environmental
protection, energy security and job creation.
8
include many of the following features: guaranteed access to the electricity grid for renewable
technologies; a fixed price for kWh of electricity produced which is typically based on a levelized
cost calculation plus a targeted return on investment; prices that are differentiated by
renewable technology, project size, and sometimes location; declining prices (termed
degression) in later years to encourage technological innovation; lengthy contract terms, often
20 to 25 years; and, a focus on streamlining administrative and regulatory process to shorten
installation lead-times.
The counter party of the feed-in-tariff contract is usually the government or one of its agencies.
The cost of the contracts (the difference between the energy price received and the amount
paid to the generator), is typically passed on to consumers in the form an electricity market
uplift charge.
Effects on Electricity Prices, GHG Emissions and Renewable Investment
As a result of the structure of cost recovery associated with feed-in-tariffs, consumers are
exposed to the average price of implementing these carbon-free technologies as opposed to the
marginal price of carbon emission.
Denmark, Germany and Spain have engaged in ambitious feed-in-tariff programs. Their
electricity costs have also increased very substantially, in some cases there has been a doubling
in real terms. Ontario’s feed-in-tariff program began in 2009 and is also associated with very
significant rate pressures.
As long as renewables, brought in through feed-in-tariffs, generally replace fossil fuel
generation, there should be substantial environmental benefits. However, in jurisdictions where
wind production is high during off-peak hours, such as at night, the environmental benefits may
be more limited, particularly if renewable production is displacing baseload generation such as
hydraulic or even nuclear production. In short, as there is no direct price on carbon, increases in
renewable generation resulting from FITs do not necessarily lead to commensurate
displacement in fossil fuel generation and cost-effective reductions in GHG emissions.
2.2.2 Competitively Tendered Renewable Procurement Programs
We touch briefly on renewable procurement programs. They share many of the advantages and
disadvantages of feed-in-tariff programs. They are however, in general, more cost-effective in
that prices paid for acquired generation are determined by a bidding process which is subject to
competitive forces, rather than a governmental agency.
2.3
Renewable Portfolio Standards
Renewable portfolio standards (RPS) have been implemented most widely in the U.S. Under
these programs, a governmental agency fixes the quantity (or percentage) of electricity to be
produced or acquired from renewable sources by major electricity producers. Utilities may then
choose to develop renewable generation or to purchase it from verifiable sources. RPS
programs are typically combined with a trading system whereby companies exceeding their
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targets can sell their surplus to others who have not met their prescribed targets. Such trading
increases the efficiency of the system.
RPS programs have several features that enhance their compatibility with market driven
electricity industries. First, the technological choice is devolved to market participants. Second,
as long as the standards are applied reasonably and equitably across producers, the impacts
should not represent a burden that would cause exit from the industry, though the financial
consequences can be material. Third, the standard may be thought of as a constraint, which will
generally put upward pressure on utility costs. These costs, however, should then be reflected
in bids submitted by market participants, which in turn should result in an orderly rationalization
of resources. In this connection, tradeable certificates also contribute to efficient allocation of
renewable generation across producers.
Effects on Electricity Prices, GHG Emissions and Renewable Investment
As the standards constrain the choices that are available to utilities for producing electricity,
there will inevitably be upward pressure on costs. However, that pressure is likely to be
significantly less than under FIT programs. Renewable investment will be induced, simply by
virtue of the standard. However, the link to GHG emissions is weaker than with a direct price on
carbon.
3. The Alberta Electricity Market and the Implications of Significant
Amounts of Renewables
3.1
Overview of the Alberta Electricity Market and its
Objectives
The objectives of the Alberta electricity market are reflected in the Electric Utilities Act. To
summarize, these are to facilitate the fair, efficient and openly competitive exchange of electric
energy, and to continue a flexible framework so that decisions about the need for, and
investment in generation are made by private industry, guided by competitive market forces.
The generation industry in Alberta is deregulated. All generation competes for the opportunity
to sell electricity into Alberta Electricity System Operator’s (“AESO”) wholesale market. The
transmission and distribution businesses in Alberta are largely regulated with the Alberta
Utilities Commission (“AUC”) having oversight over the rates recovered by asset owners. The
retail side of the business is fully deregulated for large consumers. Smaller consumers have the
ability to access regulated power rates.
At a design level, the Alberta wholesale electricity market is quite simple when compared to
other jurisdictions that have deregulated markets. The Alberta wholesale market consists of a
real-time market for energy, and various ancillary services markets.8 In contrast, other
8
Ancillary services are services required to ensure the system operates efficiently, but also reliably. The AESO uses
four ancillary services: operating reserve, transmission must run, black start and load shedding services for imports.
10
jurisdictions may administer day-ahead markets, real-time commitment programs, capacity
markets, as well as markets for ancillary products.9
The real-time energy market establishes a price for electricity on a minute by minute basis by
matching supply and demand. The minute by minute prices are averaged across an hour to
create an hourly price for settlement. Suppliers submit offers (a quantity and a price) to sell
electricity to the AESO, seven days ahead of a given delivery hour. They are free to adjust the
quantity of electricity offered at any time given an acceptable reason, and the offer price up to
two hours before the actual settlement interval. After collating the offers, the AESO creates a
supply merit order by ranking them from lowest to highest. Beginning at the bottom of the
merit order, the AESO then dispatches suppliers to produce electricity up to the point where
sufficient electricity has been dispatched to satisfy demand. The offer price of the last quantity
dispatched from the merit order sets the system marginal price for electricity. There are caps
and floors that bound the price level. Offer prices must not exceed the cap of $999.99/MWh,
nor can they be lower than $0/MWh.
The Alberta market design is particularly unique in that it functions as an “energy-only” market
where generators only receive revenue for the energy they produce and deliver to the grid.10
Some jurisdictions operate capacity markets and provide generators with capacity related
payments for being available to produce energy, even if they are not actually called to do so.
These capacity payments are intended to complement the energy revenues earned and to thus
provide a reasonably certain stream of revenues. In the result, investors enjoy greater
confidence in their ability to recover fixed operating and capital investment costs.11 Other
jurisdictions like Ontario rely on long-term contracts and a central planning process to attract
needed investment. The salient point is that unlike any other deregulated market, the Alberta
energy-only market places the preponderance of risk associated with new investment onto
participants in the competitive market. Decisions with respect to the type and quantity of
generation to be built, as well as its location, are made by private investors with considerable
uncertainty associated with the rate of return on their investment. This risk can be mitigated
through forward markets or long term contracts with, for example, industrial loads.
At a structural level, the Alberta electricity market operates essentially as an oligopoly. There
are five participants that control 70 percent of the total installed capacity in the Province with
the largest two suppliers controlling approximately 30 percent. As in any oligopoly structure,
these firms have some price setting ability and possess a degree of market power.
There are a number of features of the Alberta market that have enabled it to function effectively
as an “energy-only” market and to support investment.
The basic supply and demand fundamentals in Alberta have been positive. Above all factors,
investment decisions are driven by the fundamentals of energy supply and demand balance.12
9
Many of these additional market design features act to transfer operations, scheduling and investment risk from
generators to consumers.
10
Some generators also receive revenues for providing ancillary services.
11
Jurisdictions such as PJM, NYISO, NEISO operate capacity markets.
12
A recent report commissioned for the IRC ISO/RTO Council concluded that the key driver of investment in any
market is strong supply and demand fundamentals. See
http://www.isorto.org/Documents/Report/201505_IRCResourceInvestmentReport.pdf .
11
There has been continued economic growth in Alberta leading to electricity demand growth and
the need for new generation. The recent change in hydrocarbon prices is likely to attenuate
growth, at least in the oil and gas sector.
Political and regulatory acceptance of market power and a commitment to basic market
principles. It appears to be widely recognized and generally accepted in Alberta that the mere
unilateral exercise of market power by suppliers may be a necessary and healthy part of a
workably competitive market. While regulatory oversight and market monitoring is required to
protect against the potential anticompetitive effects of collusion or other efficiency distorting
conduct, care must be given that this oversight and regulatory intervention does not chill
incentives to innovate or invest. Alberta appears to have properly achieved this balance.
Relatedly, there has been a commitment to rely on market principles. There has been a
resistance by the AESO or regulators to mandate specific reserve requirements, instead allowing
prices to rise in order to attract investment when reserve margins are low and to discourage
new investment when reserve margins are high. Firms have also been able to retire plants
without politically motivated government intervention.
Open and transparent markets. Investors are more willing to commit funds in markets that have
transparent price-setting processes and that are generally free from manipulation or market
operator interference. Effective retail competition and openly traded and liquid forward
markets are also valued by investors.13 These features appear to be present in Alberta.
Political stability. There has been a reasonable level of confidence by investors of political
commitment to an energy-only market, and to political forbearance.
Existing environmental regulations have avoided causing the large simultaneous retirement of
coal plants or addition of renewable generation facilities. Large simultaneous decreases or
increases in supply, regardless of the technology, can create considerable investment
uncertainty. This is particularly true when retirements or additions are policy imposed and
unanticipated by market investors. Provincial and Federal policies toward coal have, to date, had
only a graduated and moderate effect on the retirement of coal. Similarly, the expansion of
wind generation over the last few years, while relatively significant, has not to date adversely
affected price signals or generator operation risk so as to undermine investment signals.14
3.2
The Effect of Renewables on Electricity Markets
The addition of any new resources to a market will have an impact on prices. In this regard, the
expansion of renewables is not unique. They will affect both the incumbents’ revenues and the
perceived potential revenues of new investors. The natural outcome of the market with new
entry is that incumbents may be incented to find ways to lower their costs or to retire facilities.
Potential investors may be forced to find a more cost effective form of entry or to invest their
money elsewhere. However, there are certain characteristics of renewable resources or the
incentive programs that have attracted their entry, that have had particular impacts on market
13
See http://www.isorto.org/Documents/Report/201505_IRCResourceInvestmentReport.pdf.
See a recent study by the Brattle Group that evaluated the resource adequacy of the Alberta market.
http://www.brattle.com/system/news/pdfs/000/000/041/original/Evaluation_of_Market_Fundamentals_and_Challe
nges_to_Long-Term_System_Adequacy_in_Alberta_Pfeifenberger_et_al_Mar_2013.pdf?1377791284.
14
12
outcomes in other jurisdictions that are worth considering in the context of Alberta’s “energyonly” market framework. These effects may be informative in the selection of a carbon policy or
in the consideration of the future evolution of the Alberta wholesale market.
(i) Low marginal cost, high fixed cost resources
Renewable generation resources such as wind and solar generally have low marginal operating
costs (near zero) and high fixed costs. In many jurisdictions, these resources are typically
incented to operate as “price takers,” offering their energy at or near price floors and accepting
the prevailing market price. Such resources typically do not have price setting ability.
The addition of low marginal cost renewable resources to a market can reduce wholesale
market prices in the short run. This has been referred to as the “merit-order effect.” The larger
the share of renewables, the greater the potential reduction in prices. In many jurisdictions, the
addition of wind facilities have affected off-peak prices more, as wind levels tend to be higher
during these periods. This is less true in Alberta to date, where expected diurnal wind variation
has been modest. Solar facilities, which operate only in the daytime, tend to have their largest
impact on prices at mid-day. There can also be seasonal effects on prices due to seasonal
variability in wind and solar output.
Given the cost structure of renewables (low marginal cost and high fixed cost) and, at least in
the case of wind, the tendency to sell more of their output during low price off-peak periods, it
is difficult to imagine how these facilities would be attracted to an energy-only market, absent
some form of incentive payment (a carbon price alone may not be sufficient initially to incent
renewable investment). Recent investments in Alberta, such as the 300MW Blackspring Ridge
wind project, earn energy revenues from the AESO spot market but have complemented these
revenues with long-term deals to sell renewable energy credits to Californian utilities such as
Pacific Gas & Electric.15
Increases in the amount of renewable generation can reduce the net revenues earned by other
types of generation. As mentioned above, in this regard, renewables are similar to other
sources of new supply. However, the specific incentives faced by renewables to offer and
operate in the market can distort static dispatch efficiency and possibly the long-run efficient
responses of investors. For example, contracting approaches that are “take-or-pay” – i.e., pay a
fixed price for energy produced regardless of what the actual market price is, can incentivize
inefficient production during periods of low demand when there is a surplus of other low
marginal cost resources operating. During these surplus conditions, the “take-or-pay” contract
can incent the renewable producers to continue to produce when it is socially inefficient. For
example, it may be more costly to shut-down a thermal unit for brief intervals in order to
manage a surplus of supply than to dispatch down a wind generator; by shutting down the
thermal unit, it may become unavailable in future periods, in which case more expensive
generation may be required.
15
See http://www.enbridge.com/MediaCentre/News.aspx?yearTab=en2013&id=1705914.
13
(ii) Variable and difficult to predict output patterns
The output from renewable resources is variable and, at times, potentially difficult to predict.
This can have several effects on market outcomes and market operations.
First, the variability in output, particularly when sudden and unanticipated, can cause electricity
price volatility. The effect will be more pronounced with larger amounts of renewables and in
circumstances of less diversification in type and location of renewable resources. Depending on
the magnitude of the volatility, this may provide an investment incentive for other types of
resources that can ramp up and down quickly to profitably take advantage of the price swings.
Second, the sudden and unpredictable output variability and price volatility can create
additional operating risks for traditional resources, particularly those that must make start-up
and commitment decisions well in advance of the dispatch hour; must produce a minimum
amount of output once started in order to operate stably; and are ‘slow ramping’. These
additional operating risks can affect the incentives to invest in these types of technologies.
Natural gas-fired generation which can start quickly may provide a good complement to variable
generation renewable sources such as wind and solar. A natural outcome in an energy-only
market with a carbon price or RPS policy may be for a generation investor to use a portfolio of
renewable and natural gas generation facilities to manage the different price and operational
risks.
Third, the sudden and unpredictable loss or increase in output from renewables can pose
problems for the system operator that must balance supply at all times to manage reliability.
Absent some market response, the system operator may be required to manually intervene in
the marketplace. Regular manual intervention reduces the transparency of the market to
participants which can be a deterrent to new investment.16
(iii) Contribution to surplus supply conditions
Increased output from renewables like wind during low demand hours can aggravate supply
surplus situations – i.e., periods when there is less demand than there is supply from baseload
generation or generation that must operate at minimum levels of output. Surplus situations are
often associated with periods of negative prices (in jurisdictions that allow prices to be negative)
or periods of sustained price floors.
The aggravation of supply surplus situations can affect the efficient operation of the market and
incentives to invest for two reasons. First, negative prices again imply lower net revenues for
resources that must continue to operate during these time periods. This can act as a spur for
exit or a deterrent to new entry. However, when the negative prices are caused by “take-orpay” contracts, the outcomes may not be efficient. These types of arrangements should be
avoided if possible. Second, the imbalance of supply and demand, if not addressed by a suitable
market response, may require system operator intervention (the operator may need to curtail a
generator that would otherwise want to continue to produce). As indicated above, excessive
operator intervention undermines the transparency of the market which can deter investment.
16
See http://www.isorto.org/Documents/Report/201505_IRCResourceInvestmentReport.pdf .
14
(iv) Provide discounted value as a “capacity” resource
Renewable resources, such as wind often provide limited output during peak demand periods.
In jurisdictions that operate to resource adequacy standards, the capacity value of these
resources is typically discounted, meaning more installed capacity from other resources is
required to maintain the standard. In other words, while the renewables may enjoy an
increased share of total energy, they remain a small share of the installed capacity that may be
relied upon to meet peak demand levels.
In an “energy-only” market, in order to meet peak demand in the presence of substantial
renewable capacity, there may be a need to allow prices to rise beyond current ceilings in order
to attract entry or retain existing resources. With higher peak prices, incumbent generators may
be seen to be exerting even more market power than in the past, which may have implications
for the acceptance of the “energy-only” market design by consumers or political parties. The
maintenance of the “energy-only” market may also require the AESO to operate for short
periods of time with capacity reserve margins below the level of industry standards, trusting
that prices will rise sufficiently to attract new investment. If instead, the AESO is obligated to
maintain a certain capacity reserve margin, as per industry standards, at all times, or at least not
“plan” itself into reserve shortfalls, the “energy-only” market may be untenable and some form
of capacity market may be required to incentivize this level of private investment.17
3.3
Possible Modifications to the Market to Accommodate
Large Scale Renewables
Given the effects that large scale deployment can have on market outcomes and operations and
on the incentives for investment, there are some modifications that could be made to the
current Alberta energy market that might help mitigate these effects and accommodate
significant amounts of renewables. We strongly suggest that Alberta consider our first two
recommendations as they will prove important in fostering the continued efficient operation of
the electricity market. With respect to the other recommendations, these are offered for future
consideration - pursuing any one of the market design changes listed below should depend on
the extent to which one of the market impacts discussed in section 3.2 actually materializes, and
becomes an impediment to the efficient operation of the market and to private investment
incentives.
(i) Require renewable resources to be dispatchable and use efficient incentive
mechanisms in the chosen carbon policy
If renewables are to play a large role in the electricity sector, they should be expected to
participate in essentially the same way as other “mainstream” resources. For example, in order
to encourage efficient market outcomes during supply surplus periods, renewable resources
17
Resource adequacy standards such as an obligation on the system operator to have a certain reserve margin of
installed capacity above forecasted future peak-demand levels, are administrative in nature and may require greater
capacity than the economically efficient amount. For this reason, jurisdictions that strictly adhere to this standard
have introduced capacity markets, in the form of auctions run by the system operator. The auctions establish the
standard for capacity but use competitive market forces and private investment to achieve it.
15
such as wind and solar should be required to be dispatchable under the same rules as any other
generator.18
Furthermore, if the carbon policy includes incentive payments to renewables, they should not
distort the incentives for the renewables to offer their output at their marginal operating cost
into the market. This will ensure that they are dispatched when efficient relative to other
resources.
(ii) Lower the price floor
To facilitate appropriate market responses during surplus supply hours, and efficient price
signals, the AESO should consider lowering the price floor to allow some negative price
outcomes. The price floor should be low enough to provide incentives for those generators with
the lowest opportunity cost to shut down when it is economic to do so.
(iii) Consider increasing the price cap
With a significant increase in renewables, there will be downward pressure on wholesale prices
in the short-run, particularly during off-peak periods and periods of surplus supply. At the same
time, to maintain reliability during peak demand periods, a sufficient amount of installed
capacity from non-renewable sources will be needed. In order to ensure adequate net revenues
to retain or attract the non-renewable sources, the AESO may want to consider increasing the
current price cap of $999.99/MWh or eliminating it altogether. This would allow traditional and
particularly peaking generators, to earn more of their net revenues during the peak demand
hours.
Note that any price cap is administratively defined and in theory could impede efficient
investment in an “energy-only” market. To date, this has not been the case in Alberta. Before
the AESO considers raising the cap, they may want to wait until there is evidence that the cap
represents a barrier to new entry for traditional sources of generation in the face of any policy
induced entry of renewables.
(iv) Consider increasing transparency through centralized wind and solar forecasting
In order to improve the transparency to market participants of potential wind and solar output,
and to enhance their ability to mitigate risks associated with output volatility, the AESO may
want to invest in centralized wind and solar forecasting. Forecast techniques have improved
and have been seen to be quite effective. Publishing forecasts may assist non-renewable
participants in managing their decisions to start and commit their facilities. The cost of the
service could be recovered either from renewable sources or from consumers.19
18
19
Effective April 1, 2015, wind became dispatchable in the AESO market.
We understand that the AESO already conducts centralized wind forecasting.
16
(v) Consider introducing a day-ahead market
Many jurisdictions operate both a day-ahead energy market and a real-time energy market. The
day-ahead energy market allows market participants to commit to buy or sell electricity, one day
in advance; this provides a means of mitigating price volatility or managing consumption or
production risk. Some jurisdictions also allow three-part offers and unit-commitment in the
day-ahead energy markets to help non-quick-start generation to manage their start-up risk.
Market participants can then buy and sell electricity during the course of the operating day in
the real-time energy market. The real-time energy market balances the differences between
day-ahead commitments and the actual real-time demand for electricity and electricity
production. Settlement occurs by reconciling day-ahead commitments (quantities and prices)
with actual real-time outcomes.
The AESO may consider introducing a day-ahead market as a means for all market participants
to manage any additional price or operational risk caused by increased quantities of renewables.
A day-ahead market will reward those facilities that can better predict their next day
consumption levels or production capabilities. It may also provide additional opportunities for
different supply sources to trade operational risk.
(vi) Consider the addition of new ancillary service markets
To manage the potential reliability concerns and need for system operator intervention caused
by sudden and unpredictable variability in renewable output, the AESO may want to consider
expanding the amount of ancillary services they carry or adding new ones. An ancillary service
similar to the load shedding service used to maintain sudden import loss could be adapted to
manage the sudden loss of large amounts of renewables. Other jurisdictions are also developing
new ancillary services to address the ramping needs or ramping constraints that can be
aggravated with the introduction of growing amounts of variable or intermittent renewable
generation. For example, MISO is in the process of developing both a ‘look-ahead’ commitment
tool20 and a ‘ramp management’ or ‘load following’ product.21 These initiatives have yet to be
developed and it is unclear how effective they might be, but they represent examples of
modifications that the AESO may consider if increased amounts of renewables lead to concerns
over ramping.
(vii) Consider the addition of a capacity market
As noted above, a significant increase in renewables will cause downward pressure on
wholesale prices given existing facilities, particularly during off-peak periods and periods of
surplus supply. At the same time, to maintain reliability during peak demand periods, a
sufficient amount of installed capacity from non-renewable sources will be needed. A natural
outcome of an “energy-only” market is that prices would have to rise sufficiently to provide the
incentives to either retain incumbent suppliers or incentivize new investment. There may also
have to be periods in which the level of installed capacity falls below the industry standard
reserve margin. This may ultimately become unacceptable to the AESO or its trading
20
21
See https://www.misoenergy.org/AboutUs/MediaCenter/PressReleases/Pages/Look-AheadTool.aspx.
See https://www.misoenergy.org/WhatWeDo/MarketEnhancements/Pages/RampManagement.aspx.
17
neighbours. If the AESO is obligated to maintain a certain capacity reserve margin, then some
form of capacity market may be required to incentivize this level of private investment.
Resource adequacy standards such as an obligation on the system operator to have a certain
reserve margin of installed capacity above forecasted future peak-demand levels, are
administrative in nature and may require more capacity than the economically efficient amount.
It is partly for this reason that jurisdictions which strictly adhere to this standard have
introduced capacity markets.
A capacity market is a regular auction based process run by a system operator to identify and
attract qualifying resources to meet near-term peak demand projection. The auctions establish
the standard for capacity but use competitive market forces and private investment to achieve
it. In this context, capacity, as the product being purchased, is the availability to produce energy.
Qualifying providers, which can include demand response participants, compete against each
other to sell capacity in the auction to the amount needed by the system operator to achieve
the standard. The design of capacity markets has evolved over the last ten years. Such markets
have recently operated successfully and have been able to attract private investment in
different U.S. jurisdictions.
3.4
The Ontario Experience: A transition from an energy-only
market to a “hybrid” market
Ontario represents an interesting case study of a market that combines centralized planning and
long-term contracting functions with a competitive electricity wholesale market. We provide a
brief synopsis of the Ontario experience and offer lessons learned for those in Alberta
contemplating a similar path as a means to achieve the province’s climate change goals. While
the path undertaken in Ontario may have been suitable for its political and economic
environment, Alberta’s circumstances are different and one should not expect to directly
transplant models from other jurisdictions.
Ontario officially deregulated its electricity sector in 1998 with the enactment of the Electricity
Act. The wholesale market officially opened in May of 2002. Like Alberta, the market began as
an “energy-only” market with the expectation that the energy prices would drive efficient
investment. Unlike Alberta however, the market was dominated by a single, government
owned supplier, Ontario Power Generation (“OPG”), whose ability to exercise market power was
palliated by a Market Power Mitigation Agreement between OPG and the government.22 The
uncertainty surrounding OPG’s incentives in the wholesale market and its intentions around the
return to service of certain nuclear assets had a chilling effect on the development of a liquid
forward market.23
22
At the start of the Ontario wholesale electricity market, OPG controlled the output decisions of about 80% of the
installed generation capacity. The Market Power Mitigation Agreement subjected OPG to certain price caps and
required them to divest some of their price setting assets within 3 ½ years.
23
The first report of the Market Surveillance Panel (‘MSP”), released four months after the market opened, stated
“while the Ontario electricity market has been opened to competition, it is not yet an effectively competitive
marketplace” (see page 133). In arriving at this conclusion, the MSP cited several examples of market features, and
government or system operator involvement that were interfering with the price determination process. These
included OPG’s dominant position; uncertainty around plans regarding the divesture of price setting assets;the return
18
While the wholesale market initially opened to relatively low prices, eventually price levels
doubled and rose well above the regulated price of 4.3 c/kWh that consumers had been charged
prior to deregulation. This prompted the government to announce in November of 2002 that it
would freeze prices to the previously regulated rates and retrospectively rebate consumers for
the difference. The price freeze, which was applied to low volume consumers and certain
designated consumers such as municipalities, universities, and hospitals, remained in effect until
2006. These developments impeded the evolution of a competitive retail market.
The opening of the wholesale market and the price levels that ensued made it clear that there
was a shortage of generation capacity in the province. However, given the cloud of uncertainty
around the future direction of the sector, there was no indication that private investment was
coming. In June of 2003, the government established an inquiry called the Electricity
Conservation & Supply Task force (“ECST”) to develop an action plan for attracting new
generation, promoting conservation and strengthening the transmission system. The Task
Force’s mandate became increasingly important in the fall of 2003 when the newly elected
Liberal government announced it would follow through with its campaign platform to eliminate
all coal fired generation by 2007.
The ECTS issued its report in January 2004 recommending several structural reforms to the
sector. Largely influenced by the ECTS recommendations, the government enacted the
Electricity Restructuring Act (“ERA”) in December of 2004, which created a “hybrid market”
structure that is more or less still present today. The “hybrid market” consists of a competitive
wholesale electricity market supported by a central planning and procurement function. The
competitive wholesale market is used to guide the short-term trade of electricity and other
ancillary service products. The central planning and procurement function is used to secure
longer term investment in generation and to promote and fund various conservation programs.
At the time of enactment, the Independent Electricity System Operator (“IESO”) operated the
competitive wholesale electricity market, while the newly created Ontario Power Authority
(“OPA”) managed the central planning and procurement functions.24
The ERA also further expanded the role of the government in the sector. The ERA provided
government with the legislative authority to issue directives to the OPA, creating a mechanism
through which it could directly intervene in the generation and transmission planning process.
Included in the power to issue directives was the ability to set the supply mix and goals for
conservation and renewable energy.
The government quickly acted on its new authorities and directed the OPA in March of 2005 to
execute and deliver 2,500MW of “clean energy supply” contracts with certain gas generators
and a contract for demand response. This was soon followed by a June 2005 directive to
negotiate and conclude contracts with “early movers” – companies that built generation assets
in the province in anticipation of a competitive wholesale electricity market. In the same year,
of the nuclear assets; and the effect of the IESO’s (then the IMO’s) actions on the market price through its forecasts
and use of “out-of-market” actions. Some of the specific IMO actions were criticized for specifically mitigating
efficient price increases. See
http://www.ontarioenergyboard.ca/documents/msp/panel_mspreport_imoadministered_071002.pdf.
24
On January 1, 2015, the OPA merged with the IESO to create a new organization that combined the OPA and IESO
mandates. The new merged company retained the IESO name.
19
directives were issued to the OPA to contract with Bruce Power for the refurbishment of the
Bruce A nuclear facilities, for 1,000 MW of renewable energy supply and various conservation
and demand management initiatives. The series of directives to contract seemingly precluded
the potential for future private generation investment to occur without the promise of a longterm contract from the principle buyer of generation in the province, the OPA. Eventually all
operating generation assets in the province were provided an OPA contract or in the case of
OPG, provided regulated rates.25
In June of 2006, the government issued a directive to the OPA to create an Integrated Power
System Plan to meet several supply mix targets set by the government, including targets to
increase the amount of renewables by 2,700 MW by 2010. The plan was to undergo a prudence
review by the provincial regulator, the Ontario Energy Board (“OEB”). In September of 2008, a
new directive was issued to the OPA requiring it to revisit the plan to increase the amount and
diversity of renewables, to increase the amount of distributed generation, to explore the
conversion of coal to biomass generation and to accelerate conservation initiatives. This set the
stage for the introduction of the Green Energy, Green Economy Act of 2009 which ultimately
lead to further expansion of renewables through the use of feed-in-tariffs. In 2010, the
government issued its own long-term energy plan for Ontario. The government followed up with
a new long-term energy plan in 2013. To date, the OEB has yet to review the Integrated Power
System Plan developed by the OPA.
In the meantime, the IESO initiated stakeholder discussions on improving the wholesale market
design with an eye towards preserving the role of the market and fostering the benefits of
competition. Most of these initiatives never materialized. For example, in 2004 and 2005, the
IESO looked to introduce a full day ahead market (“DAM”) and a resource adequacy market
(“RAM”) – the DAM would offer buyers and sellers greater price and operational certainty a day
ahead of real-time operations and the RAM would be used to attract private generation
investment. Neither of these initiatives were implemented, in part, due to the emerging role of
the OPA and the uncertainty surrounding the role of the market in the new hybrid structure. The
IESO re-opened the discussion towards a DAM in 2007 and 2008, but fell short of introducing a
full DAM.
In 2011, the IESO created the Electricity Market Forum made up of a group of industry and
agency representatives, the purpose of which was to recommend a plan for evolving the
wholesale market over the coming five years. The report was issued in December of 2011 and it
included several recommendation to the IESO to study general areas of design improvement.
While the IESO followed through on the studies, to date, no design changes have been
implemented.
Most recently, the IESO initiated discussions on the design and implementation of a “made in
Ontario” capacity auction to “open up the resource selection and investment process to market
forces and subject major investment decisions to a market test.”26 While the initiative started in
late 2013 it has since stalled. The initiative faced significant opposition from incumbent
generators with OPA contracts that were concerned that the potential for future government
25
The Ontario Electricity Financing Company also holds the remaining contracts that the former Ontario Hydro signed
with Non-Utility Generators.
26
See http://www.ieso.ca/documents/consult/Capacity_Market-Backgrounder.pdf at page 3.
20
directives to create over supply through other procurements would undermine the value in a
capacity auction.27
The gradual evolution from an “energy-only” market to a “hybrid market” has had some
successes but it has also likely had costs. On the positive side, the policies to eliminate coal,
encourage conservation and rapidly expand the deployment of renewables has helped to
significantly reduce the amount of GHG emissions from the electricity sector. GHG emissions
from the electricity sector have declined from 35 MT in 2005 to just 7 MT in 2014.28
Figure 1: Monthly Average Price Trends in Ontario (2005 to 2014)
On the negative side, there is a growing dissatisfaction from electricity consumers with the high
cost of electricity in Ontario.29 Figure 1 shows the trend in the monthly average all-in energy
price which includes the average monthly wholesale price, the Hourly Ontario Energy Price
(HOEP), and the Global Adjustment (GA). The HOEP represents the marginal fuel cost for
producing electricity, and is dependent on underlying supply and demand fundamentals. The GA
covers all the remaining fixed generation costs that are not recovered through the market, but
27
One of the issues that has become a challenge for the IESO when seeking changes to the market is the position that
contract holders take with respect to the need to renegotiate their contracts when a change in the market materially
affects a supplier’s economic circumstances.
28
See http://www.ontarioenergyreport.ca/pdfs/OntarioEnergyReportQ12015_Electricity_EN_Supply.pdf at page 9.
29
See for example a recent report by the Ontario Chamber of Commerce that suggests Ontario’s electricity price to be
among the highest in North America http://www.occ.ca/wp-content/uploads/2013/05/Empowering-Ontario.pdf.
21
are committed by contracts or regulation. The GA also includes the costs of delivering the
province’s conservation programs. Since 2005, there has been a steady decline in the average
monthly HOEP. This a largely due to the decline in demand (both in terms of total energy and
peak demands) and the decline in natural gas prices. On the other hand, the GA has steadily
increased over this period as more of the committed fixed generation costs need to be
recovered outside the market. Average monthly all-in energy prices have also steadily increased
as the province has added more contracted capacity to the system that further lowers the HOEP
but adds costs that need to be recovered through the GA.
Ontario has been in a state of oversupply for the last several years both in terms of installed
capacity to meet peak demand, and in terms of baseload supply during low demand periods.
From 2005 to 2013, peak hourly energy demand declined by roughly 4% and annual energy
demand declined by nearly 11%.30 Over the same period, Ontario replaced its coal generation
facilities with refurbished nuclear generation assets, natural gas generation and new renewable
energy generation such as wind, solar, hydro and biomass, with a net increase to the installed
capacity of roughly 1000MW.31 The addition of significant amounts of baseload and renewable
sources has required the IESO to manage numerous periods of “surplus baseload generation”
(i.e., when electricity production from baseload facilities, if not managed, would otherwise be
greater than demand). Ontario has become a net exporter of electricity, particularly during
periods of surplus when it sells “clean” electricity to its neighbours, at a price that is
substantially below the price paid by Ontario consumers to the suppliers that produce it. In
2013, the IESO affected changes to its market to require wind and solar facilities to become
dispatchable in order to more efficiently manage the surplus conditions.
The Ontario experience offers several lessons for Alberta. First, government involvement in the
market and government intervention can significantly chill private investment. This was evident
in Ontario right from the start of the market given the uncertainty around the role of OPG and
the sudden November price freeze. These interventions also created a sense among investors
that the government was not committed to market principles or market outcomes – something
Alberta has been able to successfully avoid to date and should aim to do going forward.
Second, government intervention is “absorbing” in that ad hoc government intervention often
begets the need for further government intervention. Once the Ontario government intervened
to address the political uproar surrounding high prices, and understood needed private
investment was not likely to come anytime soon, they were required to act swiftly. Alberta
should avoid implementing policies in the electricity sector that appear ad hoc and focused on
narrow short-term political pressures – ad hoc policies will create considerable uncertainty for
the investor community. Instead, policies should clearly state the long-term objectives and be
implemented as transparently as possible.32
Third, reliance on a single government agency to back generation investment through long-term
contracts can seriously undermine a competitive marketplace with private investors bearing
30
See IESO slide presentation at page 4, http://www.ieso.ca/Documents/consult/sac/sac-20150813-Planning-Update.pdf.
See IESO slide presentation at page 3, http://www.ieso.ca/Documents/consult/sac/sac-20150813-Planning-Update.pdf.
32
Several commentators have cited this as a criticism of Ontario’s electricity policy framework. For example, see
http://www.londoneconomics.com/wp-content/uploads/2015/01/2013-07-Structuring-the-Ontario-electricitymarket-to-produce-economically-efficient-long-term-price-signals.pdf.
31
22
substantial portions of risk. Bilateral contracting can be a healthy and natural outcome of a wellfunctioning market. It is a mechanism by which two parties trade future market risk given their
own needs, preferences for risk, and views on the direction of the markets. A single
government buyer of generation transfers risk from private investors to electricity consumers
and or taxpayers. Such an approach is less likely to lead to efficient outcomes. The existence of
a single government buyer for even a targeted portion of generation (say just for renewables)
can distort the market for bilateral contracts more generally and undermine investment
incentives for other types of generation. Finally, the single government buyer can also become
a convenient instrument of the government for carrying out ad hoc polices, which has been the
case with the OPA in Ontario. The government issued 93 directives to the OPA during its 10 year
existence, many that had more to do with the achievement of broader economic policy goals or
local area job retention, than sound utility style planning goals. 33
Fourth, investment decisions in Ontario have been shaped to a large degree by a series of
shifting policy objectives, and not by competitive market forces or traditional utility planning.34
Reducing GHG emissions is a worthy objective. But Alberta should be wary of abandoning the
use of market discipline in its pursuit of these goals.
3.5
Potential Impacts of Alternative Options on the Alberta
Electricity Market
Alberta has invested in a market-based electricity structure. In considering alternative carbon
policies, it is therefore important to assess potential impacts on the electricity market and to
determine whether the established benefits are likely to be eroded or substantially undermined.
In the extreme case, it is useful to ask whether a competitive market, as currently conceived,
becomes untenable.
For the purposes of this report, we take as a given that the current structure has been largely
successful in providing Alberta with reliable and cost-effective electricity supply. As such,
policies which tend to undermine the existing model are less preferable to those which are
relatively compatible with present arrangements.
We also assume that the Provincial goal is to substantially reduce emissions in the electricity
sector. We do not presume a specific time-frame for achieving these reductions.
Market-Based Options
Market-based options such as cap-and-trade or carbon taxes are generally compatible with
electricity markets. We focus on the former here.35
33
See http://powerauthority.on.ca/about-us/directives-opa-minister-energy-and-infrastructure.
This is a point made in http://www.londoneconomics.com/wp-content/uploads/2015/01/2013-07-Structuring-the-
34
Ontario-electricity-market-to-produce-economically-efficient-long-term-price-signals.pdf.
35
Cap-and-trade was successfully used to phase out leaded gasoline in the U.S. The European emissions trading
system has faced challenges with respect to price stability and predictability. Nevertheless, the European Union has
been seen as successful in reducing carbon emissions, albeit with significant increases in electricity prices.
23
Consistent with market based provision of conventional power, carbon mitigation and
technology decisions are devolved to markets. In a cap-and-trade system, permits may be
thought of as another production input, to be acquired in presumably competitive markets. In
an environment of falling hydrocarbon prices, (which comprise a substantial portion of Alberta
electricity generation fuel costs) the financial impacts on incumbent electricity generators and
ultimately electricity customers, would be ameliorated.
If, initially, permits are allocated to incumbent electricity generators without charge, there is
likely to be wider acceptance and the transition may be more easily accomplished.
In establishing a cap-and-trade system, predictability of caps and total available permits is
important in order to preserve incentives for investment in new generation, be it conventional
or renewable. Even in these circumstances, permit prices will likely be difficult to forecast.
However, given the Alberta energy-only electricity market, this additional element of
uncertainty would likely be managed more effectively by incumbent utilities than in a
jurisdiction where generators rely heavily on long term contracts and government direction.
Long-Term Contracting Options
A policy that creates a single government agency to provide long term contracts to targeted
renewable technologies would create significant risks for the existing energy-only market,
particularly if renewable energy is to comprise a significant and growing portion of supply. In
our view, the current energy-only market structure would not be sustainable.
Feed-in-tariffs are highly effective in increasing the share of renewables. This has proven to be
the case in Germany, Spain, Denmark and Ontario. However, they have typically been
accompanied by substantial increases in electricity prices and repeated government
interventions in the electricity industry.
Suppliers of renewable generation that have take-or-pay contracts and are not subject to
dispatchability obligations can distort the dispatch efficiency and ultimately the long-run
investment efficiency of the market. Incumbents may experience declines in capacity factors
and an increase in the volatility of demand for their services. During periods when renewables
such as wind or solar are on line, there is likely to be downward pressure on market prices with
lower returns to those companies that rely on the marketplace to cover their operating and
fixed costs.36
This, in turn complicates project planning and development, and may discourage investment in
the industry, particularly in conventional generation. To offset increased risk, incumbents may
seek long-term contracts for conventional supply.
A larger role for government agencies in long term contracting generally also increases
regulatory and political risks faced by market participants.
36
This is referred to as the ‘merit order effect’. Statistical evidence from other jurisdictions indicates that it has a
significant impact on prices, sometimes leading to negative prices.
24
Renewable Portfolio Standards
Renewable Portfolio Standards are relatively more compatible with competitive electricity
markets than long term contracts. However, much depends on implementation.
In this setting, the regulator will need to prescribe the proportion of electricity generation that
each major market participant will need to obtain from certified renewable sources. Participants
may choose to develop renewable supplies on their own, or to contract with renewable
generators. Tradeable green energy certificates can reduce costs and expand technological
alternatives for generators. The program design process will need to determine whether
certificates can be banked, if so for how long, and the magnitude of penalties for failure to
achieve the prescribed standard. Uncertainties about future standards and design features will
increase investment risks.
Societally efficient targets will require an analysis of abatement costs not only within the
electricity industry, but across other carbon generating sectors. While market-based options
which encompass the various GHG producing sectors intrinsically generate incentives for
economy-wide equalization of abatement costs, thus minimizing the costs of reducing carbon,
this is not the case for RPS programs. RPS calibration and determination of suitable targets can
be challenging. Tradable green energy certificates will improve efficiency, but will not resolve
this issue unless they are part of a broader inter-sectorial carbon offset trading program.
Some Alberta generating companies may find it beneficial to combine renewable supply (such as
wind) with natural gas back up in order to offer reliable and predictable bids into the energy
market. Quick-start natural gas is a natural complement to wind generation. Such arrangements
should be encouraged as generators will likely benefit from economies of scope.
4. Policy Evaluation of Options
We propose that options be evaluated according to a series of criteria, in particular, efficacy,
efficiency, administrative cost and complexity, and compatibility with the current market and
policy frameworks.
Efficacy – A key question to ask is whether the approach is likely to achieve Provincial carbon
control objectives. Some approaches target specific carbon emissions levels. Others attempt to
create incentives for reducing emissions by putting a price or tax on carbon. Still others try to
create favorable conditions for growth in renewable energy by subsidizing production or
requiring that certain quantities of renewable energy be produced or consumed. The most
direct approaches involve specifically targeting levels of carbon production, for example through
the use of cap-and-trade mechanisms. Carbon taxes, while simpler to implement, will not
necessarily result in predictable amounts of emission reductions. To the extent that an RPS
results in replacing carbon based electricity generation with carbon-free renewables, there
should be a predictable impact on emissions levels.
Efficiency – There are various types of efficiency that need to be considered. Static efficiency
refers to the ability of a scheme to promote efficient use of existing resources. Mechanisms that
have limited adverse impacts on the operation of the Alberta market-place would be consistent
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with this objective. Dynamic efficiency refers to the ability of an approach to promote efficient
evolution of the industry with respect to structure, fuel mix, investment, technological choice
and most importantly innovation. Intra-sectoral abatement efficiency refers to the ability of a
scheme to promote the equalization of abatement costs within the electricity sector. The
objective is to ensure that given reductions of carbon production within the electricity sector are
achieved at lowest cost. Inter-sectoral efficiency refers to the capacity of policies to promote
equalization of marginal abatement costs across energy sectors so that overall, provincial
abatement costs are as low as possible.
Administrative cost and complexity – This criterion refers to the administrative costs of an
approach. Complex schemes usually require greater effort and resources to execute. They may
also suffer from lack of transparency and predictability. Administrative costs include not only
those borne by regulatory agencies, but also compliance costs that are borne by companies and
ultimately consumers. For example, carbon taxes are simple to implement while cap-and-trade
schemes are more complex to administer; feed-in-tariffs may involve still greater administrative
costs as they require governmental agencies to assess appropriate target levels and to
determine tariffs that are sufficient to induce investments, keeping in mind that technological
change is having a continuous impact on these costs.
Compatibility – As indicated earlier, we take as a given the proposition that the existing
electricity industry structure has provided important benefits to Albertans. Thus a natural
question to ask is whether a given approach is compatible with that structure, whether it would
require changes to it, or whether it would fundamentally undermine it. Alberta has developed a
transparent and competitive electricity market where private initiatives are a critical driving
force ensuring reliable supply and reasonably priced electricity. Recognizing that tools for
dealing with climate change are constantly evolving, the approach should be consistent as far as
possible with the broader provincial policy framework. If that framework contemplates the
possibility of collaborating with other provinces and jurisdictions (for example, in a joint capand-trade scheme), then the choice of instruments may be informed by developments
elsewhere. Finally, compatibility with provincial economic objectives is also highly desirable.
Below we focus on evaluating three specific carbon policies – cap-and-trade, feed-in-tariffs, and
renewable portfolio standards -- against these criteria. Figure 2, provides a visual summary of
this evaluation.
Evaluation of Market-Based Options
Cap-and-trade is highly efficacious in meeting specific emissions objectives because total
permissible emissions are prescribed by the regulator. The approach does not alter the basic
incentives for cost minimization, subject to the emissions constraint, and so it should generally
lead to efficient use of existing resources. Since the price of carbon is reflected in electricity
prices, consumers are incentivized to use the product more efficiently, and to invest in costeffective conservation.
It is also dynamically efficient in that it creates incentives for innovations that reduce carbon
emissions through technology choices that are made by firms and individuals within an active
marketplace.
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The approach leads to minimization of abatement costs within the sector, and thus enjoys intrasectoral efficiency. If the scheme is expanded to cover other emitting industries within Alberta
(such as oil and gas production) then it would also likely become efficient from an inter-sectoral
perspective. There may also be additional efficiencies available through collaboration or merger
with programs in other jurisdictions.
Figure 2: Evaluation of Carbon Policy Options
Efficacy
Static Efficiency
Dynamic Efficiency
Intra-Sectoral Abatement
Efficiency
Inter-Sectoral Abatement
Efficiency
Administrative Cost
Compatibility with
competitive Alberta
elelctricity market
Cap-and-Trade
Feed-in-Tariffs
Renewable Portfolio
Standards
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Less Favourable
More Favourable
If permits are distributed without charge to existing emitters, then this can ease the transition
for generators, particularly at a time when the Alberta economy has been under pressure. The
administrative costs are significant and generally more burdensome than, e.g., carbon taxes.
A cap-and-trade program allows carbon prices to vary dynamically with the overall market
conditions and health of the Provincial economy. It may also lessen the burden on industry at
times of slow economic growth as emissions permit prices are likely to be lower.
Evaluation of Long-Term Contracting Options
Long term contracts, such as those provided under feed-in-tariffs provide price certainty,
priority of connection and dispatch. All these factors substantially reduce risks for the supplier
and transfer these risks to ratepayers. While generous feed-in-tariffs have been shown to elicit a
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strong supply response, their efficacy in reducing greenhouse gas emissions is somewhat more
tenuous. The key issue is whether the newly installed renewables displace carbon based
generation or other sources of supply. The absence of a direct connection between the
program and carbon emissions constitutes a disadvantage of FIT programs relative to cap-andtrade, or carbon taxes.
If renewable generation under a FIT contract enjoys assured dispatch or is incentivized through
a take-or-pay contract to be ranked ahead of other lower cost generators, then the system may
not be statically efficient. Furthermore, because the costs of feed-in-tariffs are recovered on a
volumetric basis so that consumers pay the average cost of such generation, and are not
charged a marginal cost of carbon, consumers are not incentivized to use the product as
efficiently.
Furthermore, as technological choices and renewable rates are determined by a governmental
agency, rather than the marketplace, innovation is likely to be less effective, thereby impairing
dynamic efficiency.
Jurisdictions that have pursued aggressive FIT policies have generally experienced substantial
increases in electricity rates.37 Spain, Germany and Denmark have engaged in ambitious FIT
programs and residential rates there have roughly doubled. While these increases cannot be
attributed entirely to FITs, such programs do generate substantial rate pressures. Updated
implementation modalities for FITs can reduce the rate pressures, for example, if renewables
are acquired through a bidding process. Ontario implemented FITs and has experienced large
rate increases as previously discussed.
Above, we have discussed various types of abatement efficiencies. These are the relative costs
of avoiding a unit of GHG emissions within the electricity sector and more generally across the
energy sector as a whole. Given the complexity of estimating and predicting abatement costs, it
would be difficult to achieve high degrees of efficiency in this respect through a program of
administered contracts. Market-based options would be much more effective in this regard.
Finally, the introduction of administered contracts, particularly on a significant scale, would
fundamentally alter the character of the Alberta electricity market in ways that would be
difficult to reverse.
Evaluation of Renewable Portfolio Standards
Renewable portfolio standards that require electricity companies to produce a certain
proportion of their output from renewable sources do not directly ensure specific reductions in
GHG emissions. From this perspective, they are not as efficacious as a cap-and-trade program.
However, choices with respect to operations and technology are devolved to firms, thus they
are likely to achieve substantially higher levels of static and dynamic efficiency than FIT
contracts. If combined with a system of tradable certificates of offsets, they may achieve high
levels of abatement efficiency, both within and outside the electricity sector.
37
See, e.g., Green, R. and A. Yatchew 2012: “Support Schemes for Renewable Energy: An Economic Analysis”,
Economics of Energy & Environmental Policy, 1, 83-98.
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The administrative costs of the RPS falls largely to utilities themselves, though the Government
would need to establish and monitor the market for green energy certificates.
A renewable portfolio standard system could be designed in such a way that it is compatible
with the Alberta electricity market. Conceptually, an RPS constitutes an additional constraint on
choices made by utilities.
A renewable portfolio system would pass on the average cost of renewable technologies to
consumers, which would likely put some upward pressure on electricity prices. This instrument
does not price carbon directly, and so in time may be supplanted by a cap-and-trade approach
or a carbon tax. On the other hand, from a governmental perspective, its implementation could
be executed relatively quickly.
5. Concluding Comments
The Alberta energy-only market can function effectively and efficiently with the addition of
further amounts of renewable energy generation. We recommend that the AESO require
renewables to be dispatchable and that the design of the renewable incentive mechanisms
preserve the incentives for the renewables to offer in the electricity market in a manner that
reflects their marginal costs of production. We also recommend that the AESO lower the price
floor sufficiently to provide incentives for those generators with the lowest opportunity cost to
shut down when it is economic to do so.
Market-based carbon policies like cap-and-trade would be most compatible with the principles
of the Alberta electricity market. A cap-and-trade system directly targets total emissions and
hence is highly efficacious. It would lead to the reduction and even minimization of abatement
costs within the electricity sector and across other covered sectors. It would also promote static
and dynamic efficiency in the electricity sector. A cap-and-trade system is technology neutral
and adheres to “causer pay” principles.
A renewable portfolio standard is generally compatible with the Alberta electricity market and
an investor-owned generation system, particularly when combined with tradeable green energy
certificates. From a governmental perspective, implementation of a renewable portfolio
standard could be executed relatively quickly and in time be supplanted by a cap-and-trade
system.
Long term contracts for specific renewable technologies, are the least compatible with the
principles of the Alberta electricity market. Overlaying government-backed administered
contracts would fundamentally alter the character of the Alberta electricity market in ways that
would be difficult to reverse. Such programs may be less effective at delivering on a specific
carbon reduction goal because they constitute a subsidy to renewables, rather than a cost
associated with carbon production. Increased renewable production does not necessarily
displace carbon based generation. In Ontario, for example, it can displace hydraulic or even
nuclear supply. Jurisdictions that have pursued aggressive FIT policies have generally
experienced substantial increases in electricity rates.
In order to provide for an orderly and effective transition it is essential that a clear policy
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position be taken, ideally one that expresses continued support for an electricity market with a
suitable and orderly incorporation of incentives for decarbonization. In the absence of a clear
commitment by the Government to preserve the market structure, there is likely to be
reluctance on the part of investors to undertake the required risks.
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APPENDIX: Biographies
Brian Rivard is a principal in CRA’s Energy Practice. He specializes in energy market design,
market analysis, and market monitoring matters. Prior to joining CRA, Dr. Rivard was the
Director of Markets at the Independent Electricity System Operator (IESO) in Ontario. While
working at the IESO, Dr. Rivard was responsible for providing analysis of the impacts of changes
to the IESO Market Rules or Market Design, government policies, and other industry initiatives.
For almost 15 years at IESO, he helped support the development of market-based approaches to
managing Ontario’s electricity system needs.
In addition, Dr. Rivard spent six years as a senior economist with the Canadian Competition
Bureau. He has written articles for various publications such as the Canadian Competition
Record, Antitrust Law Journal, and the Journal of Economic Theory as well as chapters included
in Competition Policy and Intellectual Property Rights in the Knowledge-Based Economy and
Payments Systems in the Global Economy: Risks and Opportunities.
Adonis Yatchew is Professor of Economics at the University of Toronto, Editor-in-Chief of The
Energy Journal and Senior Consultant at Charles River Associates. His research focuses on energy
and regulatory economics, and econometrics. Professor Yatchew completed his Ph.D. at Harvard
University. He has held visiting appointments at Trinity College Cambridge, the University of
Chicago, Australian National University and the University of Melbourne. He has advised public
and private sector companies on electricity, regulatory and other matters for over 25 years and
has provided testimony in numerous regulatory and litigation procedures. At the University of
Toronto, he currently teaches undergraduate and graduate courses in energy and regulation,
Ph.D. courses in econometrics, and ‘Big Ideas’ courses on Energy in the School of Environment.
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