IEEE TRANSACTIONS ON SUSTAINABLE ENERGY, VOL. 3, NO. 4, OCTOBER 2012
809
Comparison of Wind Energy Support Policy
and Electricity Market Design in Europe,
the United States, and Australia
Néstor Aparicio, Member, IEEE, Iain MacGill, Member, IEEE, Juan Rivier Abbad, Member, IEEE, and
Hector Beltran
Abstract—This paper is intended to fill a gap in the current literature comparing and contrasting the experience of a number of
European countries, U.S. states, and Australia with regard to wind
energy support policy and electricity market design. As wind penetrations increase, the nature of these arrangements becomes an increasingly important determinant of how effectively and efficiently
this generation is integrated into the electricity industry. The jurisdictions considered in this paper exhibit a range of wind support
policy measures from feed-in tariffs to green certificates, and electricity industry arrangements including vertically integrated utilities, bilateral trading with net pools, as well as gross wholesale pool
markets. We consider the challenges that various countries and
states have faced as wind generation expanded and how they have
responded. Findings include the limitations of traditional feed-in
tariffs at higher wind penetrations because they shield wind project
developers and operators from the implications of their generation
on wider electricity market operation. With regard to market design, wind forecasting and predispatch requirements are particularly important for forward markets, whereas the formal involvement of wind in scheduling and ancillary services (balancing and
contingencies) is key for real-time markets.
Index Terms—Balancing markets, electricity market design, renewable energy policy, wind energy.
I. INTRODUCTION
P
OLICY measures to support greater wind energy have
had a demonstrated impact on its development in different
jurisdictions around the world. Experience to date suggests
that feed-in tariff (FIT) policies have been the most successful
approach in rapidly expanding wind generation capacity, as
demonstrated in countries including Denmark and Spain, which
now have world leading wind energy penetrations [1]. This approach, however, may cause increasing integration challenges
for the electricity industry as wind penetrations continue to
Manuscript received August 30, 2011; revised June 08, 2012; accepted July
06, 2012. Date of publication September 10, 2012; date of current version
September 14, 2012. This work was supported in part by the Universitat
Jaume I under Grant P1·1A2008-11. N. Aparicio’s research visit to the Centre
of Energy and Environmental Markets, which kindly offered him a visiting
position, was supported by the Universitat Jaume I under Grant E-2008-06.
N. Aparicio and H. Beltran are with the Area of Electrical Engineering, Universitat Jaume I, 12071 Castelló de la Plana, Spain (e-mail: [email protected]).
I. MacGill is with the School of Electrical Engineering and Telecommunications and Centre for Energy and Environmental Markets, University of New
South Wales, Sydney 2052, Australia (e-mail: [email protected]).
J. Rivier Abbad is with Iberdrola Renovables, 28033 Madrid, Spain (e-mail:
[email protected]).
Color versions of one or more of the figures in this paper are available online
at http://ieeexplore.ieee.org.
Digital Object Identifier 10.1109/TSTE.2012.2208771
rise. The value of electricity within a power system varies over
time, by location and subject to uncertainties reflecting, in aggregate, the changing costs and benefits of all generations and
end-users. There have been worldwide moves over the last two
decades to restructure electricity industries so that generators
and end-users see price signals that more appropriately reflect
these underlying industry economics. In their simplest form,
FIT schemes can effectively shield project developers from
such energy market signals through a fixed payment for each
MWh of renewable generation independent of the value it actually provides for the industry at that time and location within
the network [2]. Simplified tendering processes awarded to
projects on the basis of lowest required government payments
per MWh of renewable generation, which were adopted in
countries such as Ireland and China, can have similar impacts.
Other policy approaches such as renewable electricity production tax credits as seen in the U.S., and tradable green certificates as seen in a number of European countries and Australia,
provide another approach for supporting wind energy. By comparison, these can ensure that wind farm developers and operators are still incentivized by electricity market “signals” to maximize overall industry value.
The last few years has seen important developments in a
number of countries that can help us better understand these
issues. For example, Denmark and Spain have moved from
a conventional FIT to a tariff premium above the electricity
market price, the latter with additional arrangements that cap
potential incomes to wind generators. The UK Renewables
Obligation scheme now appears to be driving greater industry
development, especially in offshore projects. The U.S. Federal
production tax credits and state-based renewable portfolio standards have also driven very significant if sometimes boom–bust
wind uptake, particularly in Texas with a quarter of that nation’s
installed capacity. Table I shows the total wind energy installed
capacity at the end of 2010 in the regions considered in this
paper together with their proportion of electricity consumption
now supplied by wind energy.
Wind generation penetrations have now reached significant
levels (from 10%–20%) in countries such as Denmark and
Spain, and states such as South Australia and Iowa. This, in
turn, has driven changes in electricity market design and wider
policy arrangements in these countries in order to better manage
the major contributions of highly variable and only somewhat
predictable wind generation within their power systems. Formal
participation by wind generation in electricity market dispatch
and ancillary services may be limited to day-ahead markets
1949-3029/$31.00 © 2012 IEEE
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IEEE TRANSACTIONS ON SUSTAINABLE ENERGY, VOL. 3, NO. 4, OCTOBER 2012
TABLE I
TOTAL INSTALLED WIND ENERGY CAPACITY AT THE END OF 2010 AND
THE PROPORTION OF ELECTRICITY CONSUMPTION SUPPLIED IN 2010
FOR SELECTED COUNTRIES AND REGIONS
or include real-time markets and even ancillary services such
as voltage and frequency control. Improved wind forecasting
systems have reduced prediction errors, whereas delayed gate
closures and active demand participation have decreased the
potential energy imbalances that have to be resolved by the
industry. Other electricity market arrangements that may affect
wind energy are charges due to imbalances settlement, additional income due to capacity recognition and rewards when
wind generators reduce their output following orders from
transmission system and market operators.
This paper draws together some of the key experiences, challenges, and responses to growing wind penetrations in selected
jurisdictions within Europe, the United States, and Australia.
These are by no means the only countries from which lessons
might be drawn, or where significant wind industry development is underway. However, they do represent important and
interesting examples of some key current and possible future
wind markets, and the range of support policy approaches and
electricity market arrangements that may be employed to facilitate high wind penetrations. The selected states in Australia and
the U.S. are those with the highest installed wind capacities. The
paper is divided into four further sections. Section II presents
the main support policies in place for wind in these selected jurisdictions. Section III provides an overview of their different
electricity market arrangements. Section IV discusses the interactions between wind energy and the support policies and electricity markets considered in the previous two sections. Finally,
conclusions are presented in Section V.
II. SUPPORT POLICIES
A wide range of policy mechanisms to support wind energy,
or renewable energy more generally, have been used by different jurisdictions over recent decades. A general assessment
of the available support policy mechanisms and their potential
strengths and weaknesses can be found in [3]. Four general wind
energy support policy mechanisms are considered here. The jurisdictions covered in this paper that have opted for each of these
four approaches, together with their particular characteristics,
are described below and summarized in Table II.
TABLE II
RENEWABLE ENERGY SUPPORT POLICIES IN DIFFERENT REGIONS
A. Tender Schemes
The theoretical basis of tender schemes is highly
promising—governments can set a target of installed capacity
or total public expenditure, and invite prospective project developers to submit project tenders that specify the government
support—capital $ or $/MWh—required to proceed. Governments can then choose the lowest cost project providers.
Unfortunately, the experience to date with tender-based approaches is mixed. For example, a number of countries opted
for this approach in order to drive initial deployment of renewable energies but abandoned it some years later. In 1990,
the UK introduced the Non Fossil Fuel Obligation mainly as a
policy to support the nuclear industry although it also drove the
installation of a number of wind farms. Ireland introduced its
tender scheme in 1996 based on the UK model, but abandoned
it ten years later because it failed to reach its set targets [4]. It
is also notable that China adopted a franchise tender program
in 2003 that was abandoned in 2009 for onshore projects.
What proved to be irrationally low bids offered by competing
developers led to the Government selecting projects with such
low required support prices that the “winning” proponents were
later unwilling or unable to actually undertake their projects
[5]. However, China kept a tender scheme for offshore wind
APARICIO et al.: COMPARISON OF WIND ENERGY SUPPORT POLICY AND ELECTRICITY MARKET DESIGN
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farms and Denmark opened a scheme in 2005, also for offshore
wind, with very good results [6].
A number of U.S. states use tender-based processes for their
renewable portfolio standard although these may also be based
around the use of tradable certificates as outlined in the next
section. The jurisdictions using such tenders have also achieved
mixed success [7].
B. Feed-in Tariffs
Feed-in tariff schemes adopted by Denmark, Germany, and
Spain have without doubt been the primary drivers of their
significant wind energy deployment over the last two decades.
Initial policy settings in these three countries, announced in the
1990s, were similar and relatively simple schemes with a single
tariff for all renewable producers. These FIT schemes provided
an electricity consumer funded fixed price for each MWh of
generation over a given time period. Any project meeting
the scheme requirements was eligible for this payment. As
wind installed capacity started to rise, however, these policies
have been significantly amended. Each country has followed
different strategies.
Germany has decided to make important changes in the FIT
scheme, including fixed degression, an equalization scheme that
tries to compensate the differences in wind resources between
regions, and higher tariffs for repowering and offshore wind
farms. The latest amendment of the German Renewable Energy
Act, in force since January 1, 2012, has increased the degression
for both onshore and offshore projects. However, the reduction
in offshore tariffs will not be applicable until 2018 instead of the
originally proposed 2015. An optional accelerated repayment
model which offers a higher initial tariff for a reduced number
of years has also been introduced for offshore wind farms. This
amendment also introduced a new market premium, opening the
possibility for direct selling (or direct marketing), which has important implications for the generators that participate, as it is
shown latter in the paper. German amendments have managed
to keep annual increases in installed capacity relatively constant
over the past decade as Fig. 1 shows.
Denmark phased out its FIT scheme in 2000. After a transition period, it adopted a scheme where the “feed in” tariff is now
a fixed premium payment above and beyond what the wind farm
projects earn from the electricity market. In Denmark’s case,
wind generators connected to the grid after January 2003 must
sell their production to the electricity market. Fig. 1 shows that
new installed capacity rapidly declined following this change.
However, and as noted above, the tendering process for offshore
wind farms has driven more than 200 MW of new capacity in
both 2009 and in 2010, and in 2013 the Denmark’s largest offshore wind farm with 400 MW will start operation and is expected to supply 4% of the country’s demand. This will help to
meet the Danish target of 50% from wind by 2020.
Spain introduced the option of wind farms taking an FIT premium in addition to energy market prices in 1998, earlier than
Germany, but also kept the conventional FIT mechanism. Thus
wind energy producers are able to choose between both remuneration schemes and switch between them every 12 months.
No wind energy producers initially decided to participate in the
Fig. 1. Annual increases in installed wind capacity in Spain, Germany, and
Denmark from 2002 to 2011. Sources: Respective national wind associations.
electricity market so an amendment in 2004 provided extra incentives to switch. By the end of 2006, around 90% of wind
generation capacity bid in the market as those arrangements provided higher revenues than the conventional FIT. Finally, further amendments, announced in 2007, modified the tariffs introducing a cap and a floor in the sum of market price plus premium, variable degression depending on inflation, and lower
tariffs once a technology target has been reached. Many wind
energy developers accelerated the installation of their projects
in order to complete them before this amendment came into effect at the beginning of 2008. The year 2007, therefore, saw a
record increase in installed capacity, as shown in Fig. 1. The decrease in new installed capacity over the last two years is due
to the “pre-assignation” register introduced by the Spanish government in 2010. A limited number of projects are approved in
order to ensure Spain does not surpass its targets for the wind.
Moreover, in January 2012, the government announced a temporary moratorium that freezes policy support for any new renewable energy project due to the impacts of the Global Financial Crisis.
Ireland and China have now replaced their tender schemes
with FITs. In Ireland, FITs have become the main mechanism for
supporting wind energy. Offshore wind farms have had higher
tariffs since 2008 [4]. In August 2009, China announced its first
FIT scheme for onshore wind with different tariffs that depend
on the wind resources and investment conditions in each of four
regions [8].
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C. Quota System/Tradable Certificates
A quota system is usually related with tradable renewable energy certificates (or credits) and has different names depending
on the country. In the UK, the scheme that came into force in
2002 is known as Renewables Obligation (RO). Wind generators received a Renewable Obligation certificate (ROC) for each
MWh of electricity generated. A 2008 amendment introduced
the concept of ROC banding in order to give additional ROCs
to emerging technologies. Thus, onshore wind, included in the
“reference” band, receives 1.0 ROC per MWh, while offshore
wind, which is included in the “postdemonstration” band, initially received 1.5 ROCs per MWh. The 2009 budget raised it
to 2 ROCs for 2009/10 and 1.75 for 2010/11. The ROCs are sold
to electricity suppliers in order to fulfil a mandated obligation
placed upon them by the government according to its national
renewable energy quota or target. Suppliers can either present
enough ROCs to cover their obligations or they can pay for any
shortfall into a buyout fund. The Renewables Obligation Order
2009 introduced significant changes. It requests the Secretary
of State to announce the obligation level six months preceding
an obligation period. This obligation level is the greater value
of either the number of ROCs needed to meet a fixed target of
ROCs/MWh or a headroom that is calculated as the ROCs expected to be issued according to the amount of renewable electricity expected to be generated, uplifted by 10%. This “guaranteed headroom” mechanism sets an effective floor for ROC
prices once the obligation is reached. In the case where ROC
supply exceeds the obligated demand, therefore, the RO system
will then effectively operate in a similar manner to an FIT premium mechanism.
The Australian Government’s Mandatory Renewable Energy
Target (MRET) commenced operation in 2001 as the world’s
first renewable energy certificate trading scheme [2]. It requires
all Australian electricity retailers and wholesale electricity customers to source an increasing amount of their electricity from
new renewable generation sources. The liable parties within the
Australian electricity market are electricity retailers and those
large consumers who purchase directly from the wholesale
market. The “additional renewable electricity” that the liable
parties are required to acquire was originally intended to be
equivalent to 2% of their electricity purchases by 2010. The
Renewable Energy Target (RET) announced in 2009 raised the
requirement to 20% by 2020. Targets to date have been easily
met and the costs seem reasonable by international standards
[2].
Some State Governments have also set jurisdictional renewable goals although they are not backed with specific obligations. For example, in 2007, South Australia set a 20% target
for 2014. In June 2011, it has been already met. The state, therefore, set a new goal of 33% by 2020 [9]. Victoria, which has
the second highest installed wind capacity, has a 2020 goal of
25%, with a minimum of 20% for wind energy. However, it is
intended that the Federal RET provide almost all wind project
support in Australia. A number of changes have been made to
the scheme over its decade of operation beyond a greater target,
including separate arrangements for large-scale and small-scale
renewable energy systems [2].
IEEE TRANSACTIONS ON SUSTAINABLE ENERGY, VOL. 3, NO. 4, OCTOBER 2012
Currently, there is no a federal quota scheme in the U.S. However, 29 states, the District of Columbia, and Puerto Rico have
a Renewable Portfolio Standard (RPS), and eight states have a
renewable portfolio goal.
Texas adopted both an RPS and a renewable energy credit
(REC) trading program in 1999 [10]. The RPS target was
2000 MW of new renewable generation by 2009, in addition
to the 880 MW installed at the time. It was raised in 2005 to
5880 MW by 2015, where 500 MW must be resources other
than wind, and to 10 000 MW by 2025. According to the 2009
compliance report, Texas had already surpassed its 2025 target
by 2009. The Electric Reliability Council of Texas (ERCOT)
acts as the program administrator of the REC trading program.
Iowa passed one of the earliest renewable energy laws in
the U.S. in 1983. It allocated 105 MW of renewable generating capacity between the two Iowan investor-owned utilities:
Mid-American Energy Company (MEC) and Alliant Energy Interstate Power and Light (IPL) [10]. As Table I shows, the requirement has been clearly surpassed so both utilities have been
authorized to export RECs by participating in Midwest Renewable Energy Tracking System, Inc. (M-RETS). Renewable generators used for meeting the RPS are not allowed to export RECs
in order to avoid double-counting [11]. A voluntary goal of
1000 MW of wind energy capacity by 2010, established in 2001,
has also been easily exceeded. Section 476.53 in Code of Iowa
(2009) provides that it is the intent of the general assembly to
attract the development of electric power generating facilities
within the state. Thus, when eligible new electric generation is
constructed by a rate-regulated public utility, the Iowa Utilities
Board, upon request, must specify in advance the ratemaking
principles that will apply when the costs of the new installation are included in electricity rates. In March 2009, pursuant to
section 476.53, MEC filed an application for determination of
advance ratemaking principles for up to 1001 MW of new wind
generation to be built in Iowa from 2009 through 2012. In December 2009, the Board took up MEC’s proposal. As a result,
MEC has installed significant wind generation capacity and is
expected to have a total 2284 MW by the end of 2012.
Minnesota introduced two separate RPS policies in 2007, one
for the utility Xcel Energy and the second for other electric utilities. The latter includes public utilities providing electric service, generation, and transmission cooperative electric associations, municipal power agencies, and power districts operating
in the state [10]. The RPS for Xcel Energy requires 30% of its
total retail electricity sales in Minnesota to come from renewable sources by 2020. It included a minimum of 25% for wind
energy but a State Senate Bill passed in 2009 added a maximum
of 1% from solar to this requirement. Thus, at least 24% must
come from wind energy, up to 1% may come from solar energy,
and the other 5% may come from other eligible technologies.
The RPS for other utilities requires 25% of their total retail electricity sales in Minnesota to come from renewable sources by
2020 without any technology minimums. Minnesota has been
included in the M-RETS since 2008. This tracking system program ascribes the same amount of credits to all eligible technologies independently of the state where electricity is generated. Xcel Energy is not allowed to sell RECs to other Minnesota
utilities for RPS-compliance purposes until 2021.
APARICIO et al.: COMPARISON OF WIND ENERGY SUPPORT POLICY AND ELECTRICITY MARKET DESIGN
California launched an RPS in 2002 with a target for its
electric utilities to have 20% of their retail sales derived from
eligible renewable energy resources in 2010 [10]. Senate Bill
X1-2, enacted in 2011, raised the requirement to 33% by
2020. The Bill also established three categories, also known
as buckets, of RPS-eligible electricity applicable to contracts
executed from June 2010. The decision adopted in December
2011 by the California Public Utilities Commission provides
detailed requirements for the three categories. Category one is
for electricity that is from an RPS-eligible generation installation that has its first point of interconnection with a California
Balancing Authority (CBA); scheduled from an RPS-eligible
generation installation into a CBA without substituting electricity; or dynamically transferred to a CBA. Category two is
for electricity that is firmed and shaped, providing incremental
electricity scheduled into a CBA. Category three is for those
transactions that do not meet the criteria of any of the two
previous categories, including unbundled RECs. There are
limitations on the amount of generation procured in categories
two and three that become increasingly narrow over time.
Category one generation is required to be a minimum of 50% of
the total for the compliance period ending in 2013, 65% for the
compliance period ending in 2016, and 75% thereafter. Until
the portfolio content categories become sufficiently clear, the
utilities are preferencing power purchase agreements (PPAs)
with installations that definitely belong to category one. Given
California’s increasing target, it is envisaged that PPA opportunities in categories two and three will expand in time, and with
greater clarity on the arrangements.
The Western Renewable Energy Generation Information
System (WREGIS) tracks the renewable energy generated in
the region covered by the Western Electricity Coordinating
Council (WECC), California included. WREGIS issues certificates for every REC generated, which can be used to verify
compliance with state RPS. However, currently WREGIS is
not able to track the three new portfolio content categories.
D. Tax Credits
The U.S. Federal production tax credit (PTC) for wind has
had a checkered history over the past decade. The latest extension of 2009 provides an income tax credit of 2.2¢/kWh until the
end of 2012 while adding a number of provisions. Taxpayers eligible for the PTC are allowed to take a business energy investment tax credit (ITC) equal to 30% of the construction costs for
the installation or to receive a cash grant of equivalent value if
construction began by the end of 2011. Before 2009, installation owners that did not generate enough taxable income were
unable to utilize PTC so they had to monetize the PTC through
tax equity investors.
The PTC, which applies for the first ten years of electricity
production [12], has been remarkably successful in supporting
wind deployment when it has been in place. However, during
the periodic lapses of the PTC prior to congressional renewal,
the state-based RPS mechanisms alone were not able to sustain
the growth of wind power [13]. As it represents a credit against
passive income, the PTC has a significant resemblance to an
FIT premium. In fact, both are a fixed cash incentive provided
to each kWh generated by wind.
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Finland is the only EU country which uses tax incentives as
the main support scheme for renewable energies. This policy,
however, has not been effective for wind development [6].
III. OVERVIEW OF ELECTRICITY MARKETS
AROUND THE WORLD
Jurisdictions around the world have taken a wide range of approaches to electricity industry restructuring over the past three
decades. Care must, therefore, be taken when comparing industry approaches and performance. Generally, countries with
restructured electricity industries have both forward markets
and real-time markets. In the forward markets, electricity is
traded either centrally on a power exchange or bilaterally directly between market participants. A key role for the forward
markets is to support unit commitment of those thermal generators that require generation scheduling a day prior to energy delivery. In the day-ahead markets, electricity is traded in intervals
(settlement periods) that may be one hour long or less depending
on the market design. A key challenge for these arrangements
is that unexpected generator outages or changes in demand can
take place between the closing of the day-ahead market and delivery the next day. Intraday markets permit market participants
to trade closer to the delivery time, up until just prior to the gate
closure. Intraday markets are commonly a continuous trading
market that operates with a gate closure set one hour ahead of
the settlement period [14]. After gate closure, it is no longer
possible to change bids and offers for the settlement period.
From gate closure until real-time, the difference between supply
and demand is continuously balanced through real-time markets, where transmission system operators (TSOs)—or independent system operators (ISOs) or regional transmission organizations (RTOs)—purchase the energy needed to match supply
to demand and to solve any network constraints. These organizations also have a responsibility for imbalance settlement.
Charges apply to generators if their energy deliveries differ from
the offers submitted to the market. The payment depends on the
price system. This may be a two-price system, which has one
price for imbalances with the same sign as the system net imbalance (prejudicial for the system since they contribute to the net
imbalance) and a different price (lower) for imbalances with opposite sign (beneficial since they counteract the net imbalance);
or a one-price system, which has only one price for all imbalances. Normally, the two-price system is used, since it encourages market participants to limit their imbalances according to
whether they add to, or subtract from, net system imbalances.
To ensure power system security and reliability, ancillary services are needed, including frequency and voltage control and
black-start capability. TSOs or their equivalent organizations
purchase ancillary services from service providers. Frequency
control ancillary services are commonly traded on a market that
has marked similarities to the electricity market.
Gate closure, the duration of settlement periods, and imbalance settlement arrangements are all potentially very important
for wind energy integration. The brief descriptions of electricity market arrangements for each of the jurisdictions that
we are considering here, therefore, pay special attention to
these features.
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IEEE TRANSACTIONS ON SUSTAINABLE ENERGY, VOL. 3, NO. 4, OCTOBER 2012
A. Denmark
The four countries comprising the Nordic region (i.e., Denmark, Sweden, Norway, and Finland) are among the first to have
restructured their electricity industries. In 1993, they connected
their individual markets creating Nord Pool Spot, which was
the world’s first multinational power exchange. Nord Pool Spot
trades 74% of the electricity generated in the Nordic region.
The rest is traded through bilateral contracts. It also operates a
day-ahead market called Elspot, and an intraday market called
Elbas. Elspot trades in one-hour intervals and closes at 12:00.1
It introduced different area prices in order to deal with network
congestion between countries and within Norway [15]. Elbas
is a continuous intraday market that covers the Nordic Region,
Germany, and Estonia with a gate closure one hour before delivery. This intraday market is becoming increasingly significant as more wind energy enters the grid given that imbalances
between its day-ahead contracts and produced volumes often
need to be offset [15]. As discussed below, these market arrangements are now being changed in ways that affect wind energy
directly.
Since April 2011, the gate closure for trading in Germany
has been reduced to 30 min. Negative prices have also been
introduced in all market areas since mid-February 2011 in order
to price oversupply [16].
Each local TSO has a different set of ancillary services costs
according to their procurement arrangements and reserve requirements. Energinet.dk is the Danish TSO and purchases different ancillary services in Western and Eastern Denmark as the
former is synchronously connected to the UCTE system and the
latter to the Nordel system. Denmark settles imbalances using
a two-price system. Norway used one-price system until 2008.
Since then, all Nordic countries have used a two-price system
for production imbalances and a one-price system for consumption imbalances [17].
B. Spain
Spain belongs, with Portugal, to Mercado Ibérico de la Electricidad (MIBEL)—the Iberian Electricity Market. Each country
may have different prices (splitting) in the case of transmission restrictions. All market participants can either arrange bilateral physical contracts or participate in a day-ahead market.
As with the Danish market, this day-ahead market is divided
into one-hour settlement periods and closes at 12:00. After the
day-ahead scheduling, generator positions can be adjusted in the
intraday market. Rather than being a continuous market, it is divided into six sessions. Each session has a different gate closure
(around 2 hours) as well as a different time of delivery scope (up
to 9 hours in the sixth session).
The provision of ancillary services follows the general rules
common in the UCTE system. The primary control is a compulsory service shared across all generators and without remuneration. The secondary control is performed within control areas
according to the requirements, in MW, set by the Spanish TSO
(Red Eléctrica de España). The generators willing to offer this
1This
time of day and the following ones are in 24-h notation.
service bid their power available and a market clearing process
calculates the price per MW. The price is paid even if their services are not required (availability). The tertiary control restores
the secondary control reserves under emergency conditions and
while it is optional for generators to formally participate, the
TSO can call upon any generator should it be required. By contrast with secondary control reserves, tertiary control services
are only paid for if used. Imbalances are settled with a two-price
system.
C. Germany
Most wind generation is not scheduled and, instead, is introduced into the electricity market through one of the country’s
four TSOs. The distribution network operators transfer the wind
generation for a fixed price to their respective TSO, which transforms the load fluctuating profiles into standard load profiles
which are sold to all utilities [18]. Customers pay an average
tariff to utilities. According to [18], this profile transformation
mechanism is not fully transparent and not cost-optimized. Furthermore, as the costs of the profile transformation are completely passed through to the network customers, there is no economic incentive to minimize these costs. This mechanism has
therefore been argued to represent an important weakness of the
German FIT scheme. However, the amendment applicable from
January 2012 [19] may help in addressing these drawbacks. Renewable generators can decide on a monthly basis to change the
remuneration mechanisms and participate in direct selling in the
electricity market. They have to forecast their production and
are directly charged for their imbalances. The additional costs
are covered by an extra premium known as management premium.
TSOs share wind energy imbalances, which reduces the need
for reserves. In order to manage this equitably, it is allocated
proportionally to the TSOs’ according to their consumption, not
their installed wind power.
D. United Kingdom
The British Electricity Trading and Transmission Arrangements (BETTA) cover England, Wales, and Scotland. Northern
Ireland has been part of the Single Electricity Market together
with the Republic of Ireland (see Section III-E) since 2007. In
BETTA, over 90% of electricity is traded through unrestricted
bilateral contracts. A power exchange permits market participants to fine tune their contracted positions. Gate closure is currently set one hour ahead of each half hourly settlement period.
ELEXON, the Balancing and Settlement Code Company, uses
a two-price system [20].
E. Ireland
The Single Electricity Market (SEM) commenced trading in
Ireland and Northern Ireland on an all-island basis in November
2007. SEM is a mandatory power exchange where all Ireland’s
electricity must be traded. It has only a day-ahead market with
a gate closure at 10:00. Energy is settled weekly. SEM plans to
develop an intraday market [21].
APARICIO et al.: COMPARISON OF WIND ENERGY SUPPORT POLICY AND ELECTRICITY MARKET DESIGN
F. Australia
The Australian National Electricity Market (NEM) includes
all states and territories other than Western Australia and the
Northern Territory. Its centerpiece is a set of regional gross-pool
spot energy and ancillary services markets that solve a security-constrained dispatch every 5 min. The Australian Energy
Market Operator (AEMO) is the wholesale market operator and
TSO for the entire system. Regions are currently located at all
borders between states within the NEM. All generating plants
of greater than 30-MW capacity (except intermittent generation
including wind) are required to participate as scheduled generators and submit offers to sell or bids to buy energy (and/or
ancillary services) in the NEM dispatch process. The predispatch processes forecasts up to 40 hours ahead of real time and
provides public forecasts of energy and ancillary service prices
and (privately to each dispatchable participant) dispatch levels
based on participant bids and offers, the demand forecasts and
the estimated effects of dispatch constraints. Demand is permitted to participate directly in the wholesale market; however,
nearly all end-users interface with the market through an electricity retailer [2].
There are eight Frequency Control Ancillary Services
(FCAS) markets to provide load following (raise and lower)
and three contingency responses of different speed (raise and
lower) between the 5-min energy dispatches. Market dispatch
co-optimizes energy and FCAS bids and offers to establish regional prices for both energy and FCAS for each 5-min period.
Commercial trading is based on these prices averaged over
30 min. Locational pricing within regions is achieved using
averaged loss factors. Importantly all generators are permitted
to change their offers (rebid) just prior to each 5-min dispatch.
Furthermore, the only commercially significant prices in the
NEM are these averaged 30-min prices—the predispatch prices
are advisory only. Note also that the NEM is an energy-only
market and participants are required to manage their own unit
commitment and other intertemporal scheduling challenges
(within a range of technical dispatch constraints).
G. Texas
ERCOT manages the electricity industry arrangements supplying 85% of Texas demand and covering 75% of state land
area. The ERCOT control area is not synchronously connected
to either the Eastern or Western Interconnection. However, it
can exchange about 860 MW through dc links. In December
2010, ERCOT switched from a zonal market to a nodal market
in order to improve price signals and dispatch efficiencies and
assign local congestion directly [22]. The day-ahead market employs a co-optimization engine that uses both energy and ancillary services offers to calculate the energy schedules and capacity awards. ERCOT closes this market at 14:30.
The real-time market is called security constrained economic
dispatch (SCED). ERCOT generally runs the SCED every 5 min
using offers by individual resources and actual shift factors by
each resource on each transmission element. The settlement periods are 15 min long.
815
H. Minnesota and Iowa
Minnesota and Iowa belong to the Midwest ISO (MISO),
which operates a day-ahead market and a real-time and operating reserves market. They coexist with both financial and
physical bilateral transactions between industry participants.
The day-ahead market simultaneously clears energy and operating reserves on a co-optimized basis for every one-hour
settlement period. Security constrained unit commitment
(SCUC) and SCED algorithms ensure the scheduling of adequate resources [23].
The real-time and operating reserves market uses an SCED
algorithm to simultaneously balance supply and demand and
to meet operating reserves requirements amongst other actions.
The gate closure is set to only 30 min ahead of delivery.
In March 2011, an important change came into effect with the
creation of a new category of resources called Dispatchable Intermittent Resources (DIRs). This category only applies to wind
farms and allows them to voluntarily participate in the real-time
market from June 2011, where they are eligible to supply energy
but not operating reserves. From September 2011, DIR imbalances are settled similarly to conventional generators although
only when an 8% tolerance band is exceeded, with a minimum
of 6 MWh and a maximum of 30 MWh, for four or more consecutive 5-min intervals within an hour. Wind generators are
exempt of imbalance charges in cases of force majeure, such as
extreme winds.
I. California
The California ISO (CAISO) has three day-ahead processes:
a market power mitigation determination, integrated forward
market, and residual unit commitment. A bid from a market
participant that fails the market power test is automatically reduced to the reference level price of that participant, and the
system determines the minimal and most efficient schedule of
generation to address local reliability. The integrated forward
market simultaneously analyzes the energy and ancillary services market to determine the transmission capacity required
(congestion management) and confirm the reserves that will be
needed to balance supply and demand based on supply and demand bids. It ensures generation meets load and that all final
schedules are feasible with respect to transmission constraints
as well as ancillary services requirements. When forecast load
is not met in the integrated forward market, the residual unit
commitment process enables CAISO to procure additional capacity by identifying the least cost resources available [24].
The real-time market produces energy to balance instantaneous demand, reduce supply if demand falls, offer ancillary
services as needed and, in extreme conditions, curtail demand.
The gate closure is set 75 min ahead of delivery. The market
has two unit commitment mechanisms. Real-time unit commitment assigns fast- and short-start units in 15-min intervals and
looks forward 15 min, while short-term unit commitment assigns short- and medium-start units every hour and looks forward three hours beyond the settlement period every 15 min. In
real-time, the economic dispatch process dispatches imbalance
volumes and energy from ancillary services. It runs automatically and dispatches every 5 min for a single 5-min interval.
816
Under certain contingency situations, CAISO may dispatch for
a single 10-min interval.
IV. WIND ENERGY PARTICIPATION IN ELECTRICITY MARKETS
A compilation of some key themes for wind energy integration coming out of the individual jurisdictional experiences is
presented as follows.
A. Wind Energy Forecasts and Generation Scheduling
Wind generators participating in day-ahead markets must predict their output before market close time (varying between 9.5 h
in ERCOT to 40 h ahead of delivery in some other markets).
The day-ahead and longer wind forecasts required for such generation scheduling are not sufficiently precise and two possible
alternatives have been put forward to help manage this. In the
first case, adopted in Germany (not for renewable generators
that participate in direct selling in the electricity market), Australia, MISO, ERCOT, and CAISO, the output of all wind generators is predicted over a range of time horizons through a centralized forecasting system. In the second approach, adopted in
Denmark, Spain, and the UK, numerous prediction companies
compete to provide forecasts for wind farm clients [25]. Note
that such wind energy forecasts have value to all market participants, not just the wind farms—another argument for centrally
provided forecasting services.
Even in industries where wind is not required to participate in forward markets there is considerable value in wind
farms and other market participants having useful day-ahead
forecasts. These can play a role in derivative market trading
around the future spot price, maintenance scheduling of wind
farms, unit commitment strategies of thermal plant, and production scheduling of hydro. There is also considerable value
in useful short-term forecasts that assist in generator bidding
in the real-time spot markets. For example, recent changes
in the Australian market arrangements have more formally
incorporated wind farms into market scheduling and ancillary
services arrangements through a semischeduled classification.
There are similarities with the new DIR category within the
MISO arrangements that was described in the previous section.
B. Imbalance Settlement
Imbalance settlement is probably the aspect of electricity
markets design that has highest impact on wind energy [17],
[26]. In general, system and market operators calculate such imbalances and settle them according to either a one- or two-price
system. This determines how the total balancing costs are
distributed and how incentives are given to market participants
[27]. With the one-price system used for balance settlement
in Norway before 2008, the balance costs of wind energy
were negligible as long as its random variability assured that
positive imbalances from some wind generation were compensated by negative ones [28]. Since 2008, all Nordic countries
have used a two-price system for production imbalances and
a one-price system for consumption imbalances [17]. Spain
originally applied a different one-price system that charged for
IEEE TRANSACTIONS ON SUSTAINABLE ENERGY, VOL. 3, NO. 4, OCTOBER 2012
all imbalance volumes independently of their direction. Now it
uses this two-price system: zero costs for producers that do not
contribute to the system net imbalance and a penalty for those
that do. Denmark, the UK, and Australia (only with Regulating
FCAS) also run a “causer pays procedure” in order to assign the
cost of the regulating power to those market participants who
are responsible for the imbalance. Note, however, that there
are inevitably difficulties in assigning such responsibilities
given the complex nature of electricity industry operation. This
kind of arrangement may impose significant charges on wind
energy so some tolerance in energy imbalance is often applied
and the prices paid by wind are often lower than those paid by
conventional generation.
In Germany, full responsibility for balancing wind generation is assumed by the TSOs. Indeed, they are in charge of forecasting, scheduling, and balancing. In the U.S., Federal order
890 assists intermittent generation with more flexible balancing
settlement [29]. For example, DIRs in MISO are only charged
if an 8% tolerance band is exceeded for four or more consecutive 5-min intervals within an hour, whereas CAISO has the
Participating Intermittent Resource Program (PIRP). Wind generators that participate in the PIRP have better arrangements.
Energy imbalances are netted on a monthly basis and settled at
a monthly weighted market-clearing price.
In Australia, the hybrid 5/30 min gross spot market with associated frequency control ancillary services (FCAS) seems reasonably supportive of wind integration [2].
Reduced gate closures permit rebidding up to few minutes
from delivery whereas in many intraday markets it is possible
to reschedule with updated forecasts of only one hour (or less
as in MISO). However, this can reduce liquidity; especially in
the case of market power (CAISO has market power mitigation). If the market is open until very close to gate closure, wind
generators are able to better forecast and manage the energy
that they actually produce. However, the closer to real time,
the fewer the conventional generators that may be available to
help wind generators to correct their position. Continuous markets permit changes to bids closer to real time (for example, in
the UK until one hour before). In Spain, by contrast, the six intraday sessions have delivery scopes up to 9 hours. There are
higher forecast errors; however, there is also a greater willingness and interest amongst the generators to change their position
(including all wind generators), so the market is likely to have
greater liquidity [18]. Experience to date suggests that intraday
prices differ little from the day-ahead prices. So this more liquid
market permits generators to improve their bids and offers at
little cost while also reducing regulation requirements. Note that
gross pool arrangements such as those of the Australian NEM
resolve short-term supply–demand balance with the compulsory
involvement of all generation and load.
Wind imbalances are significantly reduced by aggregating
the bids of wind farms over geographically dispersed locations
and large areas [26]. Active demand participation is also useful
in reducing imbalances. FERC Order 719 considers electricity
market accepting bids from demand response resources, on a
basis comparable to any others, for ancillary services that are
acquired in a competitive bidding process.
APARICIO et al.: COMPARISON OF WIND ENERGY SUPPORT POLICY AND ELECTRICITY MARKET DESIGN
C. Curtailment
An excess of wind generation may cause system operating
problems such as transmission line overloading or insufficient
regulation reserves that force TSOs or their equivalent organizations to order real-time curtailment to wind generators during
normal operation. Wind generators that reduce power may be
rewarded for this, depending on the electricity market arrangements. When rewards are given, wind generators typically earn
a percentage of what they could have generated. In Ireland it
is 100% [30] while in Spain it is just 15%. Another possibility
to reduce over-production is to permit negative wholesale
market prices [27]. Prices in electricity markets typically have
a zero-floor limit. Elbas has accepted negative prices since
2009 while Australia and some U.S. electricity markets have
permitted negative prices well before this. CAISO has proposed
to lower the bid floor from $30/MWh to $150/MWh, then
to $300/MWh. Spain may consider accepting it only for
downward regulation provision.
V. CONCLUSION
Wind generation penetrations have reached significant levels
in some countries and states around the world. In almost all
cases this has required changes in both policy support mechanisms and electricity market design in order to better manage
wind energy. Tender schemes have been successful only with
offshore wind. FIT tariff premiums are now the predominant
scheme as a market oriented transition from conventional FITs.
Denmark made the transition mandatory whereas Spain, and
Germany since 2012, introduced incentives. For the case of
Spain, they persuaded around 90% of wind generators to switch
from FITs. The “guaranteed headroom” mechanism introduced
in the UK is a way to transform the Renewables Obligation
mechanism into FIT premiums given an oversupply of ROCs.
The PTC can also be considered as a form of FIT premiums.
Quota-based approaches have had more limited application and
mixed success to date.
With regard to electricity market arrangements, imbalance
settlement is probably the element of electricity market design
that has the highest impact on wind generation. It depends on the
price system, the specific arrangements for intermittent sources,
possibilities to aggregate bids of wind farms over geographically dispersed sites and large areas, active demand participation, and gate closure. Small gate closures permit scheduling
with reduced forecast errors. However, this reduces liquidity.
In conclusion, there are complex and changing interactions
between a) the desired policy objectives of increasing wind
energy generation or renewable energy more generally, b) the
chosen policy approaches applied to facilitate greater deployment, and c) the commercial and regulatory arrangements that
govern how such wind energy is integrated into existing electricity industries. It is evident that the challenges of appropriate
policy and electricity market arrangements grow as wind penetrations increase. Some clear trends have emerged with those
countries now experiencing high penetrations. These include
the need to have wind farms more formally participating in
the electricity market mechanisms that manage supply-demand
balance over the immediate to longer-term. While this might be
817
seen as an impediment to greater wind deployment, it is better
understood as the inevitable process of wind transitioning from
a small industry contributor that can be ignored as “negative
load,” to a serious player that can greatly help in addressing our
growing energy security and climate change challenges within
the electricity sector.
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Néstor Aparicio (S’06–M’12) received the M.Sc.
degree from the University Jaume I of Castelló (UJI),
Castelló de la Plana, Spain, in 2002, and the Ph.D.
degree from Universidad Politécnica de Valencia,
Spain, in 2011.
He is an Assistant Professor of the Electrical
Engineering Area at Universitat Jaume I, with research interests in the grid integration of wind-power
generators. For 6 months, he visited the Institute
of Energy Technology of Aalborg, Denmark and
the Centre for Energy and Environmental Markets
(CEEM), Sydney, Australia in 2006 and 2008, respectively.
Iain MacGill (M’10) is an Associate Professor in
the School of Electrical Engineering and Telecommunications at the University of New South Wales,
Sydney, Australia, and Joint Director (Engineering)
for the University’s Centre for Energy and Environmental Markets (CEEM). His teaching and research
interests at UNSW include electricity industry
restructuring and the Australian National Electricity
Market, sustainable energy technologies, renewable
energy integration into power systems, and energy
policy.
Juan Rivier Abbad (M’99) received the Electronic
Engineering degree from the Universidad Pontificia
Comillas, Madrid, in 1992, and the Ph.D. degree from
the same University in 1999.
He joined the Instituto de Investigación Tecnológica (IIT) in 1992 as a research fellow and the
Electrical Department of the Engineering School
(ICAI) in 1999 as an assistant professor, both at the
Universidad Pontificia Comillas. He was a Visiting
Research Fellow at the Centre for Energy and
Environmental Markets (CEEM) of the University
of New South Wales, Australia, during the academic year 2005/06. He is
currently the Energy Management Responsible at Iberdrola Renovables. He
has experience in industry joint research projects in the field of electric energy
systems in collaboration with international and Spanish utilities, and with
energy regulatory commissions. His areas of interest are regulation, operation,
and integration of renewable energy sources generators, and electricity markets.
Hector Beltran received the M.Sc. degree in industrial engineering, in 2004, from the Universitat Jaume
I (UJI), Castelló de la Plana, Spain, and the Ph.D. degree in electrical engineering, in 2011, from the Technical University of Catalonia (UPC), Terrassa, Spain.
During 2003, he worked at the European Centre
for Nuclear Research (CERN), Geneva, Switzerland.
From 2004 to 2006, he worked as a Researcher at
the Electronic and Energy Departments of the Energy
Technologycal Institute (ITE), València, Spain. Since
2006, he is an Assistant Professor in the Electrical
Engineering Area at UJI. Meanwhile, he visited the Institute of Energy Technology, Aalborg University, Denmark (for 6 months), and the Renewable Energies Electric Systems Research Group at the Technical University of Catalonia
(UPC), Spain (for 9 months). His current research interests include massive photovoltaic integration into the grid, energy-storage systems, and microgrids.