dash for interconnection

Transcription

FEBRUARY 2016
DASH FOR
INTERCONNECTION
THE IMPACT OF INTERCONNECTORS
ON THE GB MARKET
FOREWORD
The analysis in this report reflects Aurora’s independent perspective as a leading
energy market modelling and analytics company. The analysis was originally prepared
for Aurora’s subscriber group in October 2015.
The subsequent publication of the analysis in this report has been supported by:
ABOUT AURORA ENERGY RESEARCH
Aurora Energy Research is an independent energy market analytics firm, providing
data, forecasts and insights on UK, European and global energy markets. We specialize
in understanding the industry-shaping issues over the medium to long run, focusing on
market fundamentals and regulatory context, and abstracting from short-term noise.
With rigorous economic modelling rooted in robust theory and supported by detailed
data, we are able to provide unique and powerful insights to our clients and subscribers
who include generators, developers, banks, regulators and NGOs.
Front cover image credit: NASA Earth Observatory
DASH FOR INTERCONNECTION
THE IMPACT OF INTERCONNECTORS ON THE GB MARKET
CONTENTS
EXECUTIVE SUMMARY
1
INTRODUCTION
2
10
C
Policy context.............................................................................................................................. 10
Existing interconnection capacity...................................................................................... 13
Proposed interconnection capacity.................................................................................. 14
Aurora’s modelling approach................................................................................................ 16
2
IMPACT OF INTERCONNECTORS ON GB GENERATORS
18
Interconnector flows............................................................................................................... 18
Wholesale prices ...................................................................................................................... 18
Generation................................................................................................................................... 20
Electricity and capacity market revenues...................................................................... 22
Investment in new GB generation capacity................................................................... 24
3
AN UNEVEN PLAYING FIELD FOR GB GENERATORS
25
EU support................................................................................................................................... 25
UK support................................................................................................................................... 27
Network charges exemption................................................................................................ 28
Carbon tax exemption............................................................................................................. 29
4
IMPACT OF NEW INTERCONNECTION CAPACITY ON
CONSUMER INTEREST
31
Impact of new interconnection on
consumer interest..................................................................................................................... 31
Higher costs under CfDs ...................................................................................................... 31
Security of supply in GB......................................................................................................... 32
Carbon emissions in Europe . .............................................................................................. 34
Net welfare impacts of interconnectors vary by connected market ............... 35
APPENDIX41
Aurora’s models.......................................................................................................................... 41
Fuel and carbon price assumptions...................................................................................44
Prepared by Aurora Energy Research
1
EXECUTIVE SUMMARY
EXECUTIVE SUMMARY
E
E.1 Aurora Energy Research has undertaken an investigation to assess the impact that a
buildout of interconnection capacity would have on the Great Britain (“GB”) power
market. This report documents the main findings to emerge from the analysis. While
not conclusively endorsing or rejecting the ‘dash for interconnection’ that now
characterises much of European energy policy, it highlights three key drawbacks
of more interconnection that we believe have received inadequate attention in
the GB debate so far.
1. Consumers incur significant costs, as interconnector subsidies and charge
exemptions need to be financed through taxes and electricity bills. We estimate
that these costs are big enough to make the net GB welfare impact of most
new interconnector projects negative.
2. Total European CO2 emissions increase as gas-fired generation in the GB
market is undercut by dirtier coal-fired generation in mainland Europe, which
faces a lower carbon price.
3. More interconnection does not provide additional security of supply, as it
displaces an equivalent amount of domestic baseload capacity which is at least
as reliable as interconnection and potentially more so.
E.2 These findings should not be taken to imply that domestic generation is always a
better option for the GB market than interconnection. Given the right policy and
market conditions, interconnection has the capacity to contribute towards the three
principal objectives of energy policy: affordability, decarbonisation and energy
security. Yet, Aurora’s analysis shows that the disadvantages can be substantial
too, and excessive interconnection buildout can in fact detract from affordability,
decarbonisation and energy security.
CONSUMERS INCUR SIGNIFICANT COSTS
2
DASH FOR INTERCONNECTION | THE IMPACT OF INTERCONNECTORS ON THE GB MARKET
E.3 The expected growth in interconnection capacity is largely driven by a range of
policy advantages that they enjoy over domestic generation. At both EU and GB
levels, an assortment of subsidies and charge exemptions have created a highly
favourable environment for new interconnectors. These include the following.
EXECUTIVE SUMMARY
• Subsidies and financial support available to interconnectors. Substantial
support is available to interconnector projects through Ofgem’s cap-and-floor
regime at the domestic level, in addition to financial support offered to Projects
of Common Interest through the €5.85 billion Connecting Europe Facility at
the EU level. These subsidies for interconnectors constitute a significant public
cost that should be weighed against their perceived benefits.
E
• Exemption of interconnectors from GB network charges. The EU Third
Package exempts interconnectors from GB network charges. These charges
include Transmission Network Use of System (“TNUoS”) and Balancing Services
Use of System (“BSUoS”) and transmission losses, which are paid by domestic
generators.
• Exemption of interconnectors from Carbon Price Support: Generators in
the UK are subject to higher carbon emission costs than their counterparts
elsewhere in Europe. In addition to the EU Emissions Trading Scheme Allowance
price, domestic generators are also required to pay the Carbon Price Support
(“CPS”) – an additional tax on fossil fuels used in electricity generation. However,
generators located in interconnected markets supplying electricity to the GB
market through interconnectors are not liable for the CPS, which represents
an additional cost burden on domestic generators.
E.4 We estimate that the CPS and network charge exemptions alone create
an advantage for interconnectors over domestic generators equivalent to
approximately £10/MWh, or more than 20% of the baseload electricity price.
If EU subsidies and cap-and-floor pay-outs are also taken into account, it could
be even larger. This creates an uneven playing field for domestic generators and
introduces market distortions with both short and long-term effects on efficiency
and social welfare in GB.
E.5 In order to capture the full impact that these distortions have on GB consumers
and generators, we deployed Aurora’s market-leading dynamic dispatch models
for the GB and Europe electricity systems in a comparison of two interconnection
buildout scenarios. The “Current IC” scenario assumes the 4 GW of currently
installed interconnection capacity to remain constant. The “EC targets” scenario
introduces 10 GW of additional interconnection capacity by 2030 (in line with
European Commission targets).
3
EXECUTIVE SUMMARY
E
E.6 We concluded that the introduction of 10 GW of additional interconnection
to an already uneven playing field could negatively affect both consumers and
generators in a number of important ways. While the buildout of interconnector
capacity would help lower wholesale prices and thereby induce a transfer from
producer to consumer surplus, the net impact on GB and European consumers
could be negative when benefits are weighed against the total cost of supporting
new interconnection. Our analysis found that additional interconnection could
destroy value in the GB market in the following ways.
• Negative net GB welfare impacts for most interconnected markets. From a
net welfare perspective, as shown in Exhibit 1, Aurora’s analysis finds that only
an interconnection with Norway increases GB welfare, while interconnection
with other countries decreases GB welfare. Additionally, feasible combinations
of domestic generation options are found to out-perform interconnection with
Denmark, Ireland, France and Belgium (Norway being the sole exception.)
• Up to 10% reductions in revenue to domestic electricity generators from
the electricity and capacity market.
• Significant reductions in annual load factor of domestic CCGTs, and in
captured prices for both CCGTs and peakers. Our analysis shows a relatively
lower impact on load factors of peakers, with interconnection competing
more with baseload and mid-merit generators rather than flexibility providers
(Exhibit 2). Low-efficiency CCGTs are more significantly impacted by increased
interconnection than any other technology, potentially seeing their valuation
decrease by more than 50% in a high interconnection scenario.
4
• Higher costs under Contracts for Differences (“CfDs”). Lower wholesale
prices will increase the payments made to CfD holders, who are granted a
fixed strike price and paid the difference between the strike price and the
wholesale price. Given the constraint posed by the Levy Control Framework, a
perverse effect of lower wholesale prices is the ability to support less renewable
resources.
EXECUTIVE SUMMARY
Exhibit 1
Welfare impact of an additional 1 GW interconnector added to the “Current IC” scenario in 2020 (PV2020
£bn at discount rate of 3.5%, 2014)
Consumers
Producers
Other interconnectors
Proposed interconnector
Network charges exemption
CPS exemption
E
Cap-and-floor
Total GB
6
4
2
0
0.1
-0.7
-0.9
-2
-0.8
-0.2
-4
-6
FRA
DEN
NOR
IRE
BEL
Exhibit 1
Notes: 1. Includes TNUoS, BSUoS and losses exemptions. 2. Assumes all projects are delivered under the cap-and-floor regime, with cost structures, caps, and floors broadly corresponding to the
actual projects of the corresponding countries approved for cap-and-floor by Ofgem. 3. Interconnector welfare is assumed to be split on a 50-50 basis between GB and the interconnected market.
Notes: 1. Includes TNUoS, BSUoS and losses exemptions. 2. Assumes all projects are delivered under the cap-and-floor
18
Sources: Ofgem,
AER,
regime,
with
cost structures, caps, and floors broadly corresponding to the actual projects of the corresponding countries
approved for cap-and-floor by Ofgem. 3. Interconnector welfare is assumed to be split on a 50-50 basis between GB and
the interconnected
Exhibit
2 market. Sources: Ofgem, AER
Capacity displaced by new ICs in the “EC targets”
scenario (de-rated1 GW)
New CCGT
Existing CCGT
Existing coal
Others
CCGT
Coal
Interconnection
New peakers
Total
10
8
6
4
2
Generation displaced by imports through the new
ICs in the “EC targets” scenario (TWh)
+6.6
(10.2 nonde-rated)
0
-10
-20
-7.1
-2
-4
-6
-8
(-7.2 nonde-rated)
2020
2025
2030
-30
-40
-50
2020
2025
2030
Exhibit 2
Notes: 1. De-rating factors applied to interconnectors are in line with DECC’s values announced ahead of the 2016 T-4 Capacity Market auction. Project’s for which DECC’s de-rating factors are
unavailable are instead de-rated at the mid-point values from ranges proposed by Ofgem.
Notes: De-rating factors applied to interconnectors are in line with DECC’s values announced ahead of the 2016 T-4
Capacity Market auction. Project’s for which DECC’s de-rating factors are unavailable are instead de-rated at the
mid-point values from ranges proposed by Ofgem. Sources: AER, DECC, National Grid
Sources: AER, DECC, National Grid
10
5
EXECUTIVE SUMMARY
E
E.7 Our welfare analysis included only the seven main welfare categories listed in
Exhibit 1. There are other possible costs and benefits of interconnection that were
not considered. An exhaustive exploration of these would be essential to a final
appraisal of particular interconnector projects. This would likely involve comparing
the expected system operability benefits of additional interconnectors with the
foregone system benefits of the dispatchable thermal plants that are displaced
by them.
E.8 Interconnectors could potentially provide new types of ancillary services in
the future, as well as other system operability benefits associated with linking
interconnectors to particularly underserved parts of the GB network 1 . National
Grid has estimated the net present value of these benefits at over £600 million
for a new 1 GW interconnector with France (IFA2), which is also the number that
Ofgem applied in the initial assessment of the project 2 . However, National Grid’s
methodology did not fully account for the foregone system benefits of displaced
domestic generation, which can also provide a range of important balancing and
ancillary services that improve system operability. There is not yet any convincing
evidence to suggest that the value of these lost benefits is any smaller than what
interconnectors can provide, especially given that interconnectors are not expected
to participate in the balancing market.
TOTAL EUROPEAN CO2 EMISSIONS INCREASE
1 Benefits of Interconnectors to GB Transmission System, December 2014, National Grid Electricity
Transmission.
2 SO Submission to Cap and Floor, December 2014, National Grid Electricity Transmission. Also quoted
in Cap and floor regime: Initial Project Assessment of the FAB Link, IFA2, Viking Link and Greenlink
interconnectors, March 2015, Ofgem.
6
E.9 As long as interconnectors remain exempt from paying CPS, additional
interconnection favours fossil-fuelled generation in continental Europe. Coal plants
in Europe face a lower CO2 price than their counterparts in the GB market and
can therefore produce electricity more cheaply, but they generally also fetch lower
wholesale prices in their home markets. Interconnectors that give them access to
higher wholesale prices in the GB market incentivize them to ramp up generation
and also enable them to displace British low-carbon alternatives, with perverse
effects on total emissions.
EXECUTIVE SUMMARY
Exhibit 3
Change in European emissions from 1 GW of IC
capacity with France (cumulative MtCO2)
Change in European emissions per 1 GW of IC
capacity (2020-30 cumulative MtCO2)
…increases total
emissions by…
1 GW additional IC
between GB and…
1. France
7
2. Belgium
By technology
8
2
3
1
(1)
4
2020
By country
4. Denmark
3
5. Norway
3
Exhibit 3
7
4
(4)
(7)
2025
2030
9
5
3. The Netherlands
6. Ireland
7
5
2
4
(6)
2020
1
(4)
E
CCGT
Coal
Lignite
Other
7
6
8
5
19
23
(17)
(23)
2025
2030
France
GB
Others
Notes: Assumes no change in CO2 prices as a result of additional interconnection. Sources: AER
• Interconnectors with continental Europe increase total emissions. Even though9
carbon emissions from domestic GB producers are sure to fall as domestic
fossil-fueled generation is displaced by imports, total European emissions
increase with interconnection capacity as coal and lignite-fired plants around
Europe ramp up their production and start exporting to GB (Exhibit 3). The
overall increase in emissions is most pronounced in the case of additional
interconnection between GB and France. Even though GB emissions fall by 23
MtCO2 relative to “Current IC”, this is more than offset by emissions increases
in France, as well as substantial increases in other markets with a high marginal
carbon intensity, such as Germany, Italy and The Netherlands. Close to 80%
of the increase in emissions is attributable to increased coal and lignite burn in
these four countries.
Sources: AER
• Interconnectors reward high-emitting generators outside of GB. The uneven
playing field in favour of interconnectors provides the ability for high-emitting
generators located outside of GB to take advantage of interconnector arbitrage
(price difference between GB and the connected market). As many of these
operate on the margin in their home markets, they are the main beneficiaries
of increased interconnection outside GB, in contrast to cleaner GB generators
who are the main losers. This goes against the overarching objective of
decarbonisation.
7
EXECUTIVE SUMMARY
E
E.10 These negative effects could be dampened if more countries in continental Europe
introduced similar policies to the CPS, thereby bringing the effective carbon price
faced by generators in continental markets more in line with the GB price. Indeed,
France announced its intentions to do exactly this through its Energy Transition Act
passed in July 2015, which included a Senate amendment to increase the carbon tax
to €56/tCO2 by 2020 3 . However, unless all the main European markets harmonise
their CO2 prices, there will continue to be an incentive to shift production to where
carbon-intensive generation is relatively less penalised, and more interconnection
is likely to aggravate this.
MORE INTERCONNECTION DOES NOT PROVIDE
ADDITIONAL SECURITY OF SUPPLY
E.11 While interconnection capacity can serve as an additional source of supply for the
GB market, Aurora’s analysis found that high levels of interconnection capacity will
have an uncertain impact on the security of supply. Under the current Capacity
Market design, interconnectors that secure capacity contracts effectively displace
domestic alternatives. They therefore replace one form of ‘insurance’ with another,
rather than adding an additional layer of security. Given that the availability of
interconnectors is influenced by very different factors than domestic generation,
it is even possible that this replacement reduces overall system resilience. Our
analysis found that 10 GW of interconnection buildout by 2030 could affect GB
security of supply in the following ways.
• Displacement of 7 GW of domestic capacity and up to 43 TWh of domestic
generation each year. Almost 80% of electricity imported on the new
interconnection capacity would have otherwise been produced by domestic
CCGTs (Exhibit 2). New interconnector capacity will trigger early retirement
of coal and CCGTs, and lower the amount of new capacity delivered by the
Capacity Market.
8
3 The Energy Transition for the Green Growth, July 2015, Ministry of Ecology, Sustainable Development and
Energy (France).
EXECUTIVE SUMMARY
• Near complete displacement of investments in new CCGTs over the next
two decades. Investments in interconnection occur in lieu of investments in
alternatives to interconnection (generation, electricity storage and demand
side response) that can also provide flexibility and security of supply at
competitive levels of efficiency and cost. Unlike these alternatives, the benefits
of interconnectors can be quite dependent on the similarity in generation
capacity mix of the markets being interconnected. That is, the expected benefit
of additional interconnection is lower the more similar the power markets being
interconnected are.
E
• A potential decrease in energy security. There is a credible argument that a
derated GW of interconnection is less secure than a derated GW of domestic
generation given the possibility that during a stress event in the GB market,
interconnected markets are also experiencing a stress event (for example, due
to cold, still weather) and that no power can then be imported at the time it is
most needed.
9
INTRODUCTION
1 INTRODUCTION
1
POLICY CONTEXT
1.1 In recent years, the buildout of interconnection capacity4 has become a critical policy
consideration for the Great Britain (“GB”) power market. While interconnection
capacity has the potential to contribute to the UK government’s three priorities
for the GB power sector – energy security, affordability, and decarbonisation – it
also has the potential to distort existing power market dynamics and disadvantage
GB generators and consumers if the incentives and policy support driving new
interconnection are not fully understood.
1.2 Over the next decade, decarbonisation and market integration policies supported
by an assortment of European Union (“EU”) and GB subsidies and tariff
exemptions available to interconnectors are expected to drive a surge in available
interconnection capacity. There is a potential for nearly 10 gigawatts (“GW”) of new
interconnection capacity to come online, more than tripling the installed capacity
(4 GW) currently in place in GB (Exhibit 4).
1.3 While it is unlikely that all proposed interconnector projects will materialize, the
existing pipeline of projects currently in place is indicative of the support available
for interconnectors both at the UK and EU level.
4 For the purpose of this report, the term “interconnection” refers to a cross-border transmission line by
which cross-border or inter-market trade can take place across two electricity transmission systems.
A critical distinction needs to be made between linkage of cross-border transmission systems and
transmission projects used to connect generation sites located outside of GB directly and exclusively to the
GB grid. While such generation-specific transmission projects are likely to require an interconnector licence,
they are principally about intra-market electricity flows and are therefore not considered in this report.
10
1.4 In the UK, support for more interconnection is motivated by a growing perception
of interconnected capacity as a means of ensuring security of supply while keeping
energy costs low for consumers. At the EU level, higher levels of interconnected
capacity are needed for the realization of a fully integrated and interconnected
European electricity market. While there is considerable uncertainty about the
amount of interconnection that has the potential to come online over the next
decade, there is general consensus that interconnection capacity in GB is expected
to grow at a historically unprecedented rate (Exhibit 5). These developments
warrant careful consideration of how increased levels of interconnected capacity
can alter the existing dynamics of the GB power market. This issue is the subject
of this report.
INTRODUCTION
Exhibit 4
Existing and proposed IC projects
Iceland
Interconnector
11
Norway
0.5 GW
2.0 GW
Existing
12
9
Denmark
2
4
10
GB
13
6
7
Existing IC
Proposed IC
The
3
Netherlands
5
1
8
Belgium
Proposed
Ireland
Germany
France
Exhibit 4
Capacity
(GW)
1. IFA
2.0
2. Moyle1
0.5
3. BritNed
1.0
4. East-West
0.5
5. ElecLink
1.0
6. FAB
1.4
7. IFA2
1.0
8. Nemo
1.0
9. NSN
1.4
10. Viking Link
1.0-1.4
11. Ice Link
0.7-1.0
12. North Connect
1.4
13. Greenlink
0.5
1
Notes: 1. The Moyle interconnector is undergoing repair and is operating at reduced capacity of 250 MW. It is expected to reach full capacity by 2017.
Notes: The Moyle interconnector is undergoing repair and is operating at reduced capacity of 250 MW. It is
4
Sources: Ofgem, to
Project
websites,
AERcapacity by 2017. Sources: Ofgem, Project websites, AER
Exhibit
5reach
expected
full
Existing and future GB interconnector capacity (GW)
20
Historical
NG Gone Green
NG Slow Progression
NG No Progression
NG Consumer Power
DECC
2030 target
15
10
2020 target
5
0
1985
1990
1995
2000
2005
2010
2015
2020
2025
2030
Exhibit 5
Notes: 1. The exact target expressed in GW will largely depend on the treatment of embedded generation. In this slide we assume that embedded generation is counted towards the target, i.e.
interconnection must be equal to 10% or 15% of total installed generation, including embedded generation.
Notes: The exact target expressed in GW will largely depend on the treatment of embedded generation. In this
3
Sources: National Grid Future Energy Scenarios 2015, DECC Energy and Emission Projections 2014, European Commission, AER
slide
we assume that embedded generation is counted towards the target, i.e. interconnection must be equal to
10% or 15% of total installed generation, including embedded generation. Sources: National Grid Future Energy
Scenarios 2015, DECC Energy and Emission Projections 2014, European Commission, AER
11
INTRODUCTION
1
1.5 The introduction of more interconnection between GB and other countries affects
a wide range of stakeholders, from consumers at home and abroad to the owners
of new and existing interconnectors and generation.
1.6 Interconnection capacity has the potential to accrue significant benefits to the GB
market by driving wholesale competition and improving price efficiency by creating
larger markets. Increased trade of electricity in a larger, well-connected market can
induce better utilisation of the most efficient or “cost-optimal” generation source
in the interconnected region electricity to flow from one country or region (where
prices are lower) to another (where prices are higher). A more diversified pool of
generating resources can help reduce price volatility by more readily absorbing
demand- and supply-side shocks, facilitate decreased reliance on fossil fuels and
help integrate intermittent renewable energy sources.
1.7 In theory, GB consumers could enjoy significant benefits because increased crossborder trade reduces the total cost of production, resulting in lower electricity
prices in GB. At the same time, in a low price environment in GB, domestic
generators may struggle to compete with producers in mainland Europe that
face lower carbon prices and can export to the GB market without incurring the
comparatively high GB network charges. These domestic producers could see their
profits fall sufficiently to facilitate early retirement of their generating sources.
Meanwhile, high-emitting coal and gas plants outside of GB may be incentivized to
take advantage of the price difference between GB and the interconnected market,
displacing more efficient domestic generators that face higher carbon costs and
resulting in a net increase in carbon emissions at the European level.
12
1.8 Ultimately, some stakeholders will stand to gain from increased interconnection,
while others will be negatively impacted. To consider the overall welfare effect,
it is imperative to capture all relevant costs and benefits as fully as possible by
measuring the net benefit (benefits less costs) of increased interconnection
capacity.
INTRODUCTION
1.9 In this report, we set out to assess the impact that such interconnection buildout
can be expected to have on the GB power market, addressing impacts on wholesale
electricity and capacity price levels, average load factors, and captured prices by
plant type. Next, we look into the second-order impacts of changing price and
dispatch dynamics on the electricity and capacity market revenue streams available
for domestic generators, plant retirements resulting from reduced profitability, and
impacts on future investments in new generation. Third, we look into the policies
driving the growth of new interconnection projects to understand how they result
in an uneven playing field that disfavours domestic generation. We conclude by
looking at the impact of new interconnection from the consumer perspective,
assessing the net benefit of interconnection capacity by capturing the full range
of welfare impacts across the four key stakeholder groups that operate within the
GB market: GB consumers, GB producers, the proposed interconnectors, and
existing interconnectors.
1
EXISTING INTERCONNECTION CAPACITY
1.10 Currently, the GB power market has 4 gigawatts (“GW”) of interconnection
capacity through four interconnectors providing approximately 4% of GB’s
electricity supply. It has a 2 GW interconnection with France (Interconnexion
France Angleterre (“IFA”)), 1 GW with the Netherlands (BritNed), and two links
with a combined 1 GW capacity to Ireland (Exhibit 6). The Moyle interconnector
is undergoing repair and is operating at reduced capacity of 250 MW. Planned
repair works are estimated to be completed by 2016, after which it can resume
its full capacity of 500 MW.
INTERCONNECTOR
COUNTRY
CAPACITY (GW)
YEAR OF COMMISSION
IFA
France
2.0
1986
Moyle
Northern Ireland
0.5
2001
BritNed
The Netherlands
1.0
2011
East-West
Ireland
0.5
2012
Exhibit 6
Sources: House of Commons Library (Carbon Price Floor), AER
13
INTRODUCTION
1
1.11 All but one of the existing interconnectors have been developed under a regulated
approach, whereby the investment is made by the market regulator or transmission
system operator (“TSO”) and underwritten by consumers. IFA was the first
interconnector project in the GB market developed in the mid-1980s by the
Central Electricity Generating Board in GB and its French counterpart, Électricité
de France. Since its privatisation, the GB portion of IFA operates on a merchant
basis. The Moyle interconnector between Scotland and Northern Ireland began
operation in 2002 and is controlled by Mutual Energy Limited, which is wholly
owned by Northern Irish consumers. The East-West Interconnector between
Wales and Ireland is the most recent interconnector developed in 2012 by the
Irish TSO EirGrid and is wholly underwritten by Irish consumers.
1.12 BritNed is the only project developed on a merchant basis jointly between National
Grid Interconnectors Limited5 and TenneT, the Dutch TSO. Unlike the other
interconnectors that were built and owned as regulated transmission assets,
BritNed was developed by private investment and provides its developers the full
up- and downside on their investment, in addition to exemptions from regulatory
requirements on transmission projects 6 . In approving BritNed’s exemption
application, the European Commission capped the returns for the project to reflect
its view on the risk of the investment7.
PROPOSED INTERCONNECTION CAPACITY
1.13 There are nine new interconnector projects being considered at present – three
with France, two with Norway, and one each with Denmark, Belgium, Iceland, and
Ireland (Exhibit 7). Collectively, these projects can be expected to deliver sufficient
capacity for meeting the European Commission’s 2020 and 2030 country-level
targets for interconnector capacity at 10% and 15% of total installed capacity,
respectively8 .
6 Merchant projects seek exemptions from various aspects of EU legislation, in particular around the use of
revenues from the interconnector. See Article 17 of Regulation (EC) no. 714/2009 View PDF Document.
7 Exemption decision on the BritNed interconnector, 2007, European Commission
8 In GW terms, the exact target will largely depend on the treatment of embedded generation. Aurora has
assumed that embedded generation will be counted towards the target, i.e., interconnection will equal 10%
or 15% of total installed capacity, including embedded generation.
14
5 Commercial arm of National Grid, plc.
INTRODUCTION
INTERCONNECTOR
COUNTRY
CAPACITY (GW)
YEAR OF COMMISSION
ElecLink
France
1.0
2018E
IFA 2
France
1.0
2021E
FAB
France
1.4
2024E
Viking Link
Denmark
1.0-1.4
2022E
NEMO
Belgium
1.0
2019E
IceLink
Iceland
0.7-1.0
TBD
NSN
Norway
1.4
2021E
NorthConnect
Norway
1.4
TBD
Greenlink
Ireland
0.5
TBD
Exhibit 7
1
1.14 Three of these projects – ElecLink, Nemo, and NSN – received final investment
decision in 2015. Six new interconnector projects – FAB, IFA2, Nemo, NSN, Viking
Link, and Greenlink – were granted “cap-and-floor” by Ofgem, which sets upper
and lower bounds on annual net revenue allowances to reduce the downside risk to
interconnector owners while capping excessive profits (Exhibit 8 – note that target
commissioning dates differ from Aurora’s expectations on actual commissioning
dates). Only one of these projects, ElecLink, is being developed on a merchant basis
similar to the existing BritNed interconnector.
15
INTRODUCTION
1
AURORA’S MODELLING APPROACH
1.15 Aurora has deployed its GB and European market models to assess the impact
that introduction of approximately 10 GW of additional interconnection capacity
by 2030 would have on GB power market dynamics. We compare the expected
outlook for the GB power market under two extreme scenarios of interconnection
capacity buildout (see Exhibit 9) to capture the impact of new interconnection
capacity.
• Scenario 1 – “EC targets”: Assuming 8.4 GW and 14.2 GW of additional
interconnection capacity build-out by 2020 and 2030, respectively, in line with
European Commission targets.
• Scenario 2 – “Current IC”: Assuming 4 GW of currently installed capacity to
remain constant.
1.16 Aurora’s models dynamically estimate expected interconnector flows and their
impacts on regional electricity prices. They estimate the flow of electricity on the
interconnector based on the expected half-hourly price differential between GB
and the interconnected market. In addition to these two scenarios, Aurora has
modelled an incremental 1 GW increase in interconnector capacity (assumed to
be built in 2020) separately for every foreign market that is expected to build out
interconnection with GB in the near future. This allows us to predict how each new
interconnector would affect prices and quantities in both interconnected markets,
but, importantly, also to compare interconnector projects on a like-for-like basis.
1.17 The models contain a fully specified Capacity Market module that iteratively finds
the economically consistent capacity contract allocations throughout the coming
decades and the capacity prices needed to trigger the required investments in
generation capacity, subject to the level of supply security defined by DECC’s
three-hour loss of load target. Further details on modelling methodology and
technical assumptions underlying the Aurora analysis can be found in the Appendix.
16
INTRODUCTION
Exhibit 8
Capacity of existing and proposed IC projects at their target commissioning dates, GW
1
14
12
10
+9.9
8
6
4
Final investment decision
Cap and floor granted
2
0
2015
2015
Existing
IFA
Moyle
BritNed
2016
2016
East-West
2017
2017
France
Eleclink
IFA2
Fab
2018
2018
Belgium
2020
2020
Ireland
NEMO
Greenlink1
2021
2021
Norway
NSN
North
Connect
2022
2022
2023
2023
Denmark
Viking
Link
Iceland
Ice
Link
Exhibit 8
Notes: 1. Following initial rejection for the cap-and-floor regime, Greenlink has been reevaluated and granted support in September 2015. This initial rejection will likely impact the target
commissioning date; the date presented here is the original target comissioning date.
Notes: Following initial rejection for the cap-and-floor regime, Greenlink has been reevaluated and granted
support in September 2015. This initial rejection will likely impact the target commissioning date; the date
presented here
Exhibit
9 is the original target comissioning date. Sources: Ofgem, project websites, AER
5
Sources: Ofgem, project websites, AER
Installed interconnector capacity, “EC targets”
scenario (GW)
Iceland1
Denmark
Norway
Belgium
The Netherlands
Ireland
10
France
14.2
15
12.2
+10.2
2015
The Netherlands
Ireland
France
15
10
8.4
5 3.8
0
Installed interconnector capacity, “Current IC”
scenario2 (GW)
5 3.8
2020
2025
2030
0
2015
4.0
4.0
4.0
2020
2025
2030
Exhibit 9
Notes: 1. Due to the lack of wholesale power exchange in Iceland, we do not model the Icelandic market explicitly and use Norwegian prices as a proxy instead. This is largely justified since both
countries have similar cost structures. 2. Assumes Moyle returns to full-operation by 2017.
Notes: 1. Due to the lack of wholesale power exchange in Iceland, we do not model the Icelandic market explicitly
and use Norwegian prices as a proxy instead. This is largely justified since both countries have similar cost
structures. 2. Assumes Moyle returns to full-operation by 2017. Sources: National Grid, AER
Sources: National Grid, AER
9
17
IMPACT OF INTERCONNECTORS ON GB MARKET
2 IMPACT OF INTERCONNECTORS ON
GB GENERATORS
2
INTERCONNECTOR FLOWS
2.1 Aurora’s analysis finds that under the “EC targets” scenario, the 10 GW of
additional interconnector capacity between GB and markets in mainland Europe
will principally be used for imports into the GB market rather than exports from
it, particularly in the near term. This is driven by the relative price of electricity
between GB and European markets.
2.2 Interconnector links are bidirectional – electricity can be transmitted through
them in either direction between two interconnected markets. Whenever there
exist large enough differences in the wholesale price of electricity between two
interconnected markets, there are opportunities for arbitrage, and electricity can
be exported from the market where the price is low to the market where the price
is higher. Thus, relative prices dictate the direction of interconnector flows.
2.3 Aurora’s model simulates the expected power flows on the interconnectors based
on the expected half-hourly price difference between GB and the interconnected
market, with power assumed to be flowing in the direction of the market with higher
prices. Decarbonisation measures and support for renewable energy sources in
the UK result in higher GB wholesale prices compared to other European markets.
Hence, power flows on the interconnectors are predominantly in the direction of
GB, i.e., from the interconnected market into the GB market. The fundamental
economics of interconnection dictate that GB is likely to be a net importer of
electricity from European markets (Exhibit 10).
WHOLESALE PRICES
18
2.4 Higher levels of interconnection capacity under the EC Targets scenario results in
extra imports into the GB power market. With demand remaining constant, the
additional supply of electricity from additional imports places a downward pressure
on expected future GB wholesale prices. Aurora’s analysis finds that under the
EC Targets scenario, extra imports on the 10 GW of additional interconnection
capacity depresses wholesale prices by 3% in 2020 and 7% in 2030 relative to
the Current IC scenario (Exhibit 11).
Exhibit 10
2
Imports and exports in “EC targets” scenario (TWh)
Denmark
France
Norway1
Ireland
Belgium
The Netherlands
Net import
90
Import to GB
80
70
60
50
40
30
20
Export from GB
10
0
-10
-20
-30
-40
2020
2022
2024
2026
2028
2030
2032
2034
2036
2038
2040
Notes: 1. Includes Iceland.
Exhibit 10
Notes:
1. Includes
Exhibit
11 Iceland. Sources: AER
Source: AER
GB electricity prices (£/MWh, 2014)
GB "Current IC"
GB "EC targets"
Average interconnected market price
55
50
45
-7%
-3%
40
35
30
25
2015
2020
2025
2030
2035
2040
Note: 1. Average price of markets interconnected with GB, namely Denmark, France, Norway, Ireland, Belgium and Netherlands.
Exhibit 11
Notes: Average price of markets interconnected with GB, namely Denmark, France, Norway, Ireland, Belgium and
Netherlands. Sources: AER
Source: AER
11
19
2
GENERATION
2.5 The average annual load factor and captured prices for combined-cycle gas turbine
(“CCGT”), coal plants and peaking plants decrease in the EC Targets scenario
relative to the Current IC scenario. Additional interconnection capacity in the EC
Targets scenario displaces not just flexible generation sources (peakers), but also
significantly impacts baseload generation (CCGT and coal).
2.6 Additional imports on the new interconnectors decrease utilization of CCGT,
coal, and peaking plants and lowers their average annual load factor because
interconnection capacity is dispatched in preference to these plants (Exhibit 12). For
CCGT and peakers, we observe lower captured prices over the modelling horizon
in the EC Targets scenario consistent with the general depression in wholesale
prices discussed in the previous sub-section. For coal plants, captured prices are
seen to increase in the EC Targets scenario leading up to their assumed retirement
in the mid-2020s as these plants shift to more marginal operation compared to
the Current IC scenario.
2.7 These trends in load factors and captured prices have a significant impact on the
future generation mix (Exhibit 13). In the “EC targets” scenario, 10 GW of additional
interconnection displaces 7 GW of domestic generation capacity, most of which is
baseload capacity. New interconnectors trigger early retirement of coal and CCGTs
and lower the amount of new capacity delivered by the capacity market. We find
that CCGT is the technology most significantly impacted because coal plants are
already being forced into early retirement by decarbonisation policy initiatives. We
estimate that approximately 9 medium-sized CCGT plants would be displaced by
the additional interconnection.
20
2.8 The finding that interconnection capacity displaces domestic baseload
capacity stands in marked contrast to the commonly held perception that new
interconnectors will serve primarily as a flexible generation resource in the GB
market, offering power to the GB market only when the system is tight and prices
are high. In fact, when looking at the expected total generation in the GB market,
we find that nearly 80% of electricity imported in the 2020s would have otherwise
been produced by domestic CCGTs (right-hand side of Exhibit 13).
Electricity Market
Exhibit 12
Average annual load factor (%)
CCGT1
Current IC
EC targets
Coal2
Current IC
EC targets
2
Captured prices (£/MWh, 2014)
Peaker3
Current IC
EC targets
CCGT1
Current IC
EC targets
Coal2
Current IC
EC targets
Peaker3
Current IC
EC targets
140
80
120
60
100
80
40
60
40
20
20
0
2020
2025
2030
2035
2040
0
2020
2025
2030
2035
2040
Notes: 1. Represents a 54% HHV efficiency plant. 2. Represents a 35% HHV efficiency plant 3. Represents a 35% HHV efficiency OCGT plant.
Exhibit 12
13
Notes: 1. Represents a 54% HHV efficiency plant. 2. Represents a 35% HHV efficiency plant 3. Represents a 35%
HHV
efficiency
OCGT
plant.
Sources:
AER
Exhibit 13
Source: AER
Capacity displaced by new ICs in the “EC targets”
scenario (de-rated1 GW)
New CCGT
Existing CCGT
Existing coal
Others
CCGT
Coal
Interconnection
New peakers
Total
10
8
6
4
2
Generation displaced by imports through the new
ICs in the “EC targets” scenario (TWh)
+6.6
(10.2 nonde-rated)
0
-10
-20
-7.1
-2
-4
-6
-8
(-7.2 nonde-rated)
2020
2025
2030
-30
-40
-50
2020
2025
2030
Notes: 1. De-rating factors applied to interconnectors are in line with DECC’s values announced ahead of the 2016 T-4 Capacity Market auction. Project’s for which DECC’s de-rating factors are
unavailable are instead de-rated at the mid-point values from ranges proposed by Ofgem.
Exhibit 13
Notes: 1. De-rating factors applied to interconnectors are in line with DECC’s values announced ahead of the 2016
T-4 Capacity Market auction. Project’s for which DECC’s de-rating factors are unavailable are instead de-rated at the
mid-point values from ranges proposed by Ofgem. Sources: AER, DECC, National Grid
Sources: AER, DECC, National Grid
10
21
2
ELECTRICITY AND CAPACITY MARKET REVENUES
2.9 Additional interconnection capacity reduces revenue streams available to domestic
generators in both the electricity and capacity markets (left-hand side of Exhibit
14). Total revenue streams available to domestic generators from the electricity
and capacity markets over 2015-2040 on a present value (“PV”) basis shrink by
10%. We find that while the impact of additional interconnector capacity on the
electricity market is persistently negative, the effect on capacity market is negative
in the short term and positive in the long term.
2.10 The negative impact on electricity market revenue streams is due to a combination
of lower electricity prices and reduced load factors. In the capacity market, the
presence of new interconnectors reduces the need for new thermal plants in the
2020s, placing a downward pressure on capacity prices in that period. The positive
impact on the capacity market in the longer term results from the fact that lower
revenue potential in the electricity market incentivizes generators to increase their
bids in future capacity market auctions, resulting in higher long-term capacity prices
and hence higher capacity market revenues.
2.11 By generation technology, CCGTs are most disadvantaged by increased
interconnection capacity. While we observe a decrease in total revenue for
all plant types, we note that low-efficiency CCGTs lose 61% of their value to
interconnection, followed by coal (-36%), higher-efficiency CCGTs (-29%), and
peakers (-21%). Nuclear and intermittent generation with low marginal cost are
the least significantly impacted (Exhibit 15).
22
Exhibit 14
Difference in total market revenue between “Current IC”
and “EC targets” scenarios (£bn, 2014)
Electricity market
Total market revenue 2015-2030 (PV £bn
at 10% discount rate, 2014)
Capacity market
Electricity Market
0.5
2
Capacity Market
140
0.0
126
-0.5
-10%
-1.0
-1.5
132
-2.0
119
-2.5
-3.0
-3.5
201
5
202
0
202
5
203
0
203
5
204
0
7
6
’Current IC’
’EC Targets’
Sources: AER
Exhibit 14
Exhibit
15
NPV of expected revenue streams1 (£/kW, at 10% discount rate, 2014)
"Current IC" NPV
EM gross margin
CM revenue
"EC targets" NPV
12
Source: AER
Mid-efficiency CCGT2
High-efficiency CCGT2
159
354
94
3
105
Peaker
19
3
141
100
-61%
63
Coal3
3
251
-29%
Nuclear
83
1,811
-21%
74
2
1,735
-4%
48
2
91
ROC-based onshore wind
1,284
1,207
76
0
-36%
-6%
Notes: 1. Excludes balancing and ancillary revenues. The impact of interconnection on balancing revenues depends on whether markets can be successfully coupled on the balancing market level.
If balancing markets are indeed coupled, the resulting decrease in balancing and ancillary revenues available to domestic producers can be significant. 2. 52.5% and 54% HHV efficiency,
respectively. 3. 38% HHV efficiency.
Exhibit 15
Notes: 1. Excludes balancing and ancillary revenues. The impact of interconnection on balancing revenues
15
Source: AER
depends
on whether markets can be successfully coupled on the balancing market level. If balancing markets are
indeed coupled, the resulting decrease in balancing and ancillary revenues available to domestic producers can be
significant. 2. 52.5% and 54% HHV efficiency, respectively. 3. 38% HHV efficiency. Sources: AER
23
2
INVESTMENT IN NEW GB GENERATION CAPACITY
2.12 The reduction in expected revenue streams for domestic generators in the EC
Targets scenario has a significant adverse impact on new generation investment
in the GB power market, with lower energy and capacity prices lowering returns
beyond the required hurdle rate. Under the Current IC scenario, we expect £7.7
billion to be invested in new peakers (£3.6 billion, 46%) and CCGT (£4.1 billion,
54%) over the 2016-2035 period (Exhibit 16). Under the EC Targets scenario, we
note that approximately £2 billion of investment in new interconnection lowers the
total expected investment by nearly one-fifth (to £6.2 billion) and almost entirely
displaces
investment in new CCGT (which falls to £0.4 billion) over the same period.
Exhibit 16
Uncommitted generation capex1, excluding nuclear and renewables, £bn
‘Current IC’
6
Peaking plant
CCGT
Interconnectors
5
4
3
2
“Current IC” “EC targets”
Total 2016- Total 20162035, £bn: 2035, £bn:
1
0
2016-2020
2021-2025
2026-2030
2031-2035
‘EC Targets’
2.5
2.0
1.5
3.6
(46%)
3.8
(61%)
4.1
(54%)
0.4
(7%)
1.0
2.0
(33%)
0.5
0.0
2016-2020
2021-2025
2026-2030
2031-2035
Notes: 1. Investment required to deliver anticipated generation mix that is not already post-FID. Capex for interconnectors are assumed to be split 50-50 between GB and the interconnected
market.
Exhibit 16
16
Sources: Aurora
Energy Research, DECC
Notes:
Investment
required to deliver anticipated generation mix that is not already post-FID. Capex for
interconnectors are assumed to be split 50-50 between GB and the interconnected market. Sources: AER, DECC
24
3 AN UNEVEN PLAYING FIELD FOR
GB GENERATORS
3.1 Economic theory is clear that trading power across countries, like any other form
of trade, can bring benefits to both countries. But this result requires that certain
assumptions to hold true, notably an efficient market and a level playing field
between producers in each region.
3
3.2 In the market for power within the EU, the playing field is not level. Interconnectors
receive a number of benefits and subsidies not available to GB generators,
including an assortment of subsidies at the EU and UK level, exemptions from
network charges and carbon costs, and mechanisms providing financial support
and revenue certainty for developers. We estimate that the carbon cost and
network charge exemptions alone create an advantage for interconnectors over
domestic generators equivalent to approximately £10/MWh. If EU subsidies and
cap-and-floor pay-outs are also taken into account, it could be even larger. It is this
imbalance that is driving the growth in interconnection capacity to a level that we
will conclude in the next section of this report is not optimal from a GB welfare
perspective.
EU SUPPORT
3.3 At the EU level, developments of new interconnectors continue to be driven by the
recently adopted framework strategy for the Energy Union Package, which places
significant emphasis on greater interconnection between member states9. In the
agreement, the European Commission stressed the importance of its newly agreed
target of making 10% of member states’ national generation capacity available to
other members via interconnectors by 2020, with an eye towards 15% by 2030.
3.4 In addition, the TEN-E Regulation outlines a process for identifying priority
cross-border projects every two years to support a well-interconnected energy
infrastructure. These so-called “Projects of Common Interest” (“PCI”) consist
of energy infrastructure projects that are necessary for the implementation of
the nine priority corridors and the three thematic areas identified in the TEN-E
Regulation10 .
9 European Council Conclusions on the Energy Union, 19 March 2015, European Council.
10 Regulation (EU) No 347/2013 of the European Parliament and of the Council of 17 April 2013 on guidelines
for trans-European energy infrastructure (OJ L 115, 25.4.2013, p.39).
25
Exhibit 17
3
Sources of support for interconnectors
Domestic generators
Exhibit 17
Interconnectors
Sources: AER
3.5 Almost all planned interconnector projects to the UK have been granted PCI28
status, enabling them to benefit from faster planning and permitting procedures,
regulatory incentives, and possible access to financial support from the €5.85 billion
Connecting Europe Facility (“CEF”)11 . On 4 March 2015, the Commission opened
a call for proposals to access €650m worth of CEF grants for supporting the PCI12 .
Two GB interconnector projects – ElecLink and Greenlink – were successful in the
first round of allocations and have been awarded grant agreements for EU funds
to finance development studies under the CEF. The Commission’s second call for
proposals to access CEF funds was launched on 30 June 2015, with a decision
expected in early 2016.
Source:
AER
12 CEF Energy: First Call for Proposals 2015, 4 March 2015, European Commission.
26
11 Connecting Europe Facility View Article Online
UK SUPPORT
3.6 On the domestic end, Ofgem’s “cap-and-floor” scheme has been launched to
provide revenue certainty for merchant interconnector projects. The cap-and-floor
framework will provide revenue protection up to the level of the floor, in exchange
for any revenues above the cap. As such, when revenue earned by interconnector
owners exceeds the cap level, money is transferred to consumers (via network
tariffs). On the flip side, when revenue earned is below the floor, there will be a
transfer from consumers to interconnector owners. Ofgem’s cap-and-floor scheme
thus reduces investment risk and amounts to a reduction in the cost of capital for
new investment that is not enjoyed by investors in GB generation, who also face
merchant risk.
3
3.7 On 16 October 2014, Ofgem published a shortlist of five new interconnectors
that meet eligibility criteria: FAB and IFA2 (France), Greenlink (Ireland), NSN
(Norway), and Viking Link (Denmark). Together with the ElecLink (France) and
Nemo (Belgium) projects already assessed, these seven projects could provide
up to 7.5 GW of additional interconnection capacity. The five new projects have
now successfully completed the Initial Project Assessment phase of the process,
in which Ofgem assessed the impact of the projects and whether they can
deliver value for money. On 2 December 2014, Ofgem decided to apply the new
cap-and-floor regime for the interconnector between GB and Belgium (Nemo),
and throughout 2015, the same decision was made with regards to all new projects
that can connect to the network by 2020. Greenlink, FAB, IFA 2, NSN, and Viking
Link must now submit detailed cost information to Ofgem for the Final Project
Assessment stage to determine provisional cap and floor levels.
3.8 Furthermore, following up on its earlier favourable stance on developing
interconnector capacity 13 , DECC announced on 2 December 2014 that
interconnectors could participate in the second four-year-ahead Capacity
Market auction held in December 2015 to secure energy supply for the winter of
2019-20. All the interconnectors applying for prequalification – IFA, BritNed,
and Nemo – were accepted to participate in the auction. Both existing Irish
interconnectors declined to apply for prequalification, which was expected based
on their low de-rating factors. ElecLink also did not apply for prequalification. In the
13 More interconnection: improving energy security and lowering bills, December 2013, DECC.
27
3
December 2015 auction, 2.4 GW of interconnector capacity participated, of which
1.9 GW of existing interconnection capacity (BritNed: 828 MW; IFA: 1,034 MW)
were awarded a one-year contract, while Nemo’s 0.5 GW of qualifying capacity
missed out14 . Unlike new-build domestic generators, new interconnector projects
are not eligible for 15-year capacity contracts. The option of participating in the
Capacity Market therefore does not offer the same benefits to interconnectors
in terms of merchant risk reductions and potential capital cost advantages. Yet,
Aurora’s analysis shows that interconnectors mainly compete with existing
generators (Exhibit 13) that are also not eligible for 15-year contracts.
NETWORK CHARGES EXEMPTION
3.9 In the GB power market, transmission and balancing charges – Transmission
Network Use of System (“TNUoS”), Balancing Services Use of System (“BSUoS”)
and transmission losses – represent an additional cost burden on domestic
generators relative to their continental counterparts. While domestic generators
pay nearly 27% of TNUoS and 50% of BSUoS charges in the GB market15 ,
generators’ shares of equivalent charges are close to zero in many other
European member states.
3.10 TNUoS charges recover the cost of installing and maintaining the transmission
system in England, Wales, Scotland, and offshore. Costs are split between the
generators and suppliers of electricity and recovered through a tariff based on
which geographical zone they are in, whether they are generators or suppliers,
and the size of their generation or supply16 . BSUoS charges recover the cost of the
day-to-day operation of the transmission system’s transmission losses of around
2%17. Generators and suppliers are liable for these balancing charges, which are
calculated daily as a flat tariff across all users18 .
14 Provisional auction results: T-4 Capacity Market auction for 2019/20, December 2015, National Grid.
15 Overview of transmission tariffs in Europe: Annex 1, June 2014, ENTSO-E.
16 Transmission Network Use of System charges, National Grid website.
17 Transmission losses, November 2013, Elexon.
18 Balancing Services Use of System charges, National Grid website.
28
3.11 Both TNUoS and BSUoS charges are cost recovering tariffs, and as such, the
amount of the tariff depends not only on the costs over a particular period, but
also on the customer base from which the costs are being recovered. Transmission
and balancing costs are more likely to be ‘fixed’ than ‘variable’ and hence are not
dependent on the number of transmission system users.
3
3.12 The EU Third Energy Package completely exempts interconnectors from paying
TNUoS, BSUoS, and cost of transmission losses. Even though foreign generators
normally pay some network charges in their home markets, these are neither on a
par with those charged from GB generators nor reflective of the costs imposed by
interconnectors on the GB network, and this lack of network charge harmonisation
creates potential for wide-reaching market distortions19. Aurora’s analysis shows
that, together, the comparatively low network charges faced by many European
generators and the charge exemptions for interconnectors imply higher energy
production costs for domestic generators compared to interconnection capacity
and results in interconnectors’ under-pricing, and therefore displacing, domestic
generators in the GB wholesale market.
3.13 The situation will be further aggravated if increased interconnection capacity leads
to earlier retirement of domestic generators and transmission and balancing costs
have to be recovered over a smaller customer base, resulting in higher TNUoS and
BSUoS charges for remaining domestic generators.
3.14 Additionally, Ofgem’s cap-and-floor scheme has the potential of increasing domestic
generators’ share of network charges in a low wholesale price environment to cover
the losses incurred by interconnectors, should their revenues fall below the floor.
CARBON TAX EXEMPTION
3.15 Generators in the UK are subject to higher carbon emission costs than their
counterparts elsewhere in Europe. In addition to the EU Emissions Trading Scheme
Allowance (“EUA”) price, GB generators are also required to pay the Carbon Price
Support (“CPS”), an additional tax on fossil fuels used in electricity generation.
3.16 In the March 2011 Budget, the government committed to introducing a carbon
price floor (“CPF”) price starting in April 2013. Since its implementation, supplies
of coal, gas and LPG used in most forms of electricity generation have become
liable to newly created CPS rates of the Climate Change Levy. In Budget 2011, it
19 Scoping towards potential harmonisation of electricity transmission tariff structures: conclusions and next
steps, December 2015, Agency for the Cooperation of Energy Regulators.
29
3
was announced that the carbon price floor would start at around £16 per tonne
of carbon dioxide (“tCO2”) and increase linearly to the target £30/tCO2 in 2020,
ultimately rising to approximate the social appraisal cost of carbon at £70/tCO2 by
2030 (in 2009 prices)20 . In Budget 2014, the trajectory to 2020 was changed by
flat-lining the top-up payment on the EU-ETS (the carbon price support level) to
£18/tCO221 . Under the CPF the price for carbon paid by UK generators consists
of the EUA price plus the CPS rate.
3.17 The CPS constitutes 83% of the carbon costs for domestic generators (Exhibit 18).
Because interconnection capacity is not liable to pay the CPS, the price of carbon
faced by electricity generators in the UK is effectively four times higher than in the
rest of Europe when accounting for the combined effect of CPS and EUA prices.
This implies higher input costs faced by UK-based generators, which is another
Exhibit 18
comparative advantage to interconnection capacity in the GB power market.
UK carbon price (£/tonne)
30
25
Total carbon price (Carbon Price Floor)
Carbon Price Support
EU ETS allowance
20
15
83%
10
5
0
Exhibit 18
59%
73%
41%
27%
17%
2013
2014
2015
Sources: AER
Source:
AER
20 Carbon price floor consultation: The Government response, March 2011, HM Revenue and Customs.
21 Carbon price floor: reform and other technical amendments, March 2014, HM Revenue and Customs.
22 The Energy Transition for the Green Growth, July 2015, Ministry of Ecology, Sustainable Development and
Energy (France).
30
3.18 This imbalance could be reduced if more countries in continental Europe introduced
similar policies to the CPS, thereby bringing the effective carbon price faced by
generators in continental markets more in line with the GB price. Indeed, France
provisionally announced its intentions to do exactly this through its Energy
Transition Act passed in July 2015, which included a Senate amendment to increase
the carbon tax to €56/tCO2 by 2020 22 . However, unless all the main European
28
markets harmonise their carbon prices, there will continue to be an incentive to shift
production to places where carbon-intensive generation is relatively less penalised.
IMPACT OF NEW INTERCONNECTION ON CONSUMER INTEREST
4 IMPACT OF NEW INTERCONNECTION
CAPACITY ON CONSUMER INTEREST
IMPACT OF NEW INTERCONNECTION ON
CONSUMER INTEREST
4
4.1 The main argument for interconnection is that it can support consumer interests
by contributing positively to energy security, affordability, and decarbonisation.
4.2 Aurora’s analysis finds that interconnectors do lead to lower wholesale electricity
prices in a state of the world in which 10 GW of interconnector capacity is built
by 2030. Yet, while lower wholesale prices knock on to lower retail prices and
improved affordability, we find that the net impact on GB consumers is not
positive when these benefits are weighed against the total cost of supporting new
interconnection from the public purse.
4.3 Moreover, the benefits of lower wholesale prices also need to be evaluated in
light of the higher costs that they contribute to under Contracts for Differences
(“CfDs”), the retirements of power plants (mostly CCGT) that they induce, and
the increase in carbon emissions that result as carbon-intensive generators are
allowed to exploit interconnector arbitrage in the context of the uneven playing
field for domestic generators.
HIGHER COSTS UNDER CFDS
4.4 Under the Electricity Market Reform in the UK, CfDs have emerged as the
primary framework to support low carbon generation beyond 2017, replacing
the Renewables Obligations Certificates system previously in place. Under a CfD,
the government contracts with low-carbon generators to supply electricity at a
fixed price (a strike price that varies by technology and is established through an
auction process) for 15 years. The CfD mandates that generators receive the
difference between the market wholesale price of electricity and the strike price
when wholesale prices are lower than the strike price. Conversely, generators pay
back the difference when wholesale prices are higher than the strike price.
31
Exhibit 19
4
Changes in total CfD payments resulting from additional 1 GW interconnector added to the “Current IC”
scenario in 2020 (PV2020 £million at discount rate of 3.5%, 2014)
2,447
1,446
1,406
The Netherlands
Ireland
1,251
1,149
France
Belgium
-217
Norway
Exhibit 19
Denmark
Sources: AER
4.5 The subsidization of CfD holders by consumers will increase in a low wholesale
price environment in which the market price is consistently below the CfD
strike price for the technology in question. Aurora’s analysis finds that 1 GW of
additional interconnection capacity added in 2020 above the Current IC scenario
may increase the present value of total CfD payments (which are borne by
9
consumers) over 2020-2040 by as much as £2.4 billion in the case of Norwegian
interconnection as a result of lower wholesale electricity prices (Exhibit 19). Given
the constraint posed by the Levy Control Framework – a cap on total annual
spending on support for low-carbon generation (including renewables, nuclear and
CCS) – higher payments under CfDs will imply that fewer renewable resources
can be supported.
Sources: AER
SECURITY OF SUPPLY IN GB
4.6 Interconnectors will import power into the GB market when price differentials
make it profitable to do so, but unlike domestic supply, they do not actually generate
any power. As such, the amount of ‘credit’ interconnectors should be given in the
GB capacity market towards securing sufficient supply to meet a 3-hour loss of
load target is difficult to define.
32
4.7 In the 2015 capacity market auction, the derating factors applied to interconnectors
(that is, the amount of credit they are given towards secure GB supply) were in the
range of 52-69% for continental interconnection (Exhibit 20), reflecting DECC’s
view on the amount of power they are likely to import as a percentage of the
theoretical maximum.
INTERCONNECTOR
COUNTRY
DECC23
4
Existing interconnector derating factors
IFA
France
52%
BritNed
The Netherlands
69%
Moyle/East-West
Ireland
6%
Proposed projects derating factors
ElecLink
France
56%
Nemo
Belgium
54%
Exhibit 20
4.8 But security of supply is notoriously hard to quantify, and the extent to which
interconnection could be relied upon in a GB stress event is statistically far more
complex to calculate than for domestic generators, for which historic data gives
a relatively reliable indication of availability. If, for example, a GB stress event was
triggered by cold weather and low wind speed, there is a higher than average
probability that Western Europe would also be experiencing cold weather and
low wind speed, potentially leading to higher prices on the continent and no
interconnector flows to GB at the time they were most needed.
4.9 Over the longer term, if changes in energy policy at the European level were to
result in GB electricity prices equalizing with mainland Europe, GB could stop being
a net importer of electricity and would need to rapidly replace domestic capacity
as the derating factors applied to interconnection are revised downwards.
4.10 While none of these events can be predicted with any certainty, it is the mere
possibility of their occurrence that makes the estimation of interconnector derating
factors a difficult and risky endeavour in a way that is not the case for domestic
generation.
23 Confirmation of Capacity Auction Parameters, 29 June 2015, DECC.
33
4
CARBON EMISSIONS IN EUROPE
4.11 The uneven playing field caused by CPS exemptions for interconnectors provides
the ability for high-emitting plants outside GB to take advantage of interconnector
arbitrage (due to the price difference between GB and the connected market). This
means that even though carbon emissions from domestic GB producers are sure
to fall as domestic fossil-fueled generation is displaced by imports. Total European
emissions could increase as coal-and lignite-fired plants around Europe ramp up
their production and start exporting to GB. This goes against the overarching
objective of decarbonisation.
4.12 Aurora’s modelling shows that the extent to which domestic decarbonisation is
offset by emissions increases elsewhere varies substantially, depending on the
interconnected market. For example, 1 GW of additional interconnection between
GB and Ireland is actually likely to decrease total emissions as relatively dirty coalfired generation in GB is replaced by relatively clean CCGTs in Ireland, with limited
effects on markets in mainland Europe. In contrast, an incremental increase in
the interconnector capacity with one of the continental markets in France, The
Netherlands, Belgium, Denmark, or Norway is likely to increase total European
emissions21
by some 3-7 MtCO2 over the 2020-2030 period (Exhibit 21).
Exhibit
Change in European emissions from 1 GW of IC
capacity with France (cumulative MtCO2)
Change in European emissions per 1 GW of IC
capacity (2020-30 cumulative MtCO2)
…increases total
emissions by…
1 GW additional IC
between GB and…
1. France
7
2. Belgium
By technology
8
2
3
1
(1)
7
4
(4)
(7)
2025
2030
9
5
4
3. The Netherlands
2020
By country
3
5. Norway
3
2
4
(6)
2020
1
(4)
CCGT
Coal
Lignite
Other
7
6
8
5
19
23
(17)
(23)
2025
2030
France
GB
Others
Exhibit 21
Notes: Assumes no change in CO2 prices as a result of additional interconnection. Sources: AER
Sources: AER
34
9
4. Denmark
6. Ireland
7
5
4.13 The overall increase in emissions is most pronounced in the case of additional
interconnection between GB and France. Even though GB emissions fall by 23
MtCO2 relative to “Current IC”, this is more than offset by emissions increases in
France, as well as substantial increases in Germany, Italy, and The Netherlands.
Close to 80% of the increase in emissions is attributable to increased coal and
lignite burn in these four countries. Overall, the effect is approximately equivalent
to extending the life of a major coal plant by 3 years.
4
4.14 Even with greater interconnection between GB and Norway – which is mainly
hydro-powered and therefore low-carbon – we estimate total European
emissions will increase by 3 MtCO2 over the 2020-2030 period. This is not due to
increased emissions in either GB or Norway, but rather to an exploitation of new
arbitrage opportunities by producers in other European countries, most notably by
lignite-fired generators in Germany.
4.15 This highlights that European electricity markets are interconnected through
a complex network of links between many countries, and no interconnector is
therefore truly bilateral. As long as the playing field remains uneven, increased
interconnection creates opportunities for high-emitting producers in mainland
Europe to displace low-carbon alternatives in GB.
NET WELFARE IMPACTS OF INTERCONNECTORS VARY BY
CONNECTED MARKET
4.16 The introduction of more interconnection between GB and other countries affects
a wide range of stakeholders, from consumers at home and abroad to the owners
of new and existing interconnectors. Ultimately, some stakeholders will stand to
gain from increased interconnection, while others will be negatively impacted. To
consider the overall welfare effect, Aurora has estimated the most relevant costs
and benefits as fully as possible and used their unweighted sum (benefits minus
costs) as a measure of the net benefit.
4.17 Since the objective of this study is to assess the overall impact of increased
interconnection on the GB market, this does not include consumers and producers in
the interconnected markets. Instead, this study focuses on the four key stakeholder
groups that operate within the GB market: GB consumers, GB generators, owners
of proposed interconnectors, and owners of existing interconnectors.
35
4
4.18 Exhibit 22 illustrates the welfare effects associated with increased interconnection
in the stylized case in which GB acts as a pure importer of electricity from an
interconnected market with consistently lower electricity prices (France, in this
example). The main driver of welfare creation in this case is the reallocation
of electricity generation away from the home market (GB) and towards the
lower-cost market (France), which allows GB consumers to consume the same
amount of electricity at lower cost. The main welfare categories in this example
are the following .
• Consumer surplus (orange area). For a given market, this is the total quantity
of electricity demanded by consumers times the difference between the
price of electricity and the value of lost load (“VoLL”). At a constant quantity
demanded, a fall in the price of electricity (resulting from extra imports on new
interconnectors) increases consumer surplus in the importing market (areas
A+B in the GB market), while an increase in the price of electricity decreases
consumer surplus in the exporting market (area D in the French market). Notably,
area A represents a direct transfer from producer to consumer surplus, while
area B represents a welfare creation for consumers due to lower wholesale
electricity
Exhibit
22 prices in the importing market (GB).
Welfare effects of increased interconnection (example with GB as pure importer)
Consumer surplus
Price
Great Britain (importer)
Price
Transfer
Interconnector rent
Producer surplus
France (exporter)
DemandGB
DemandFR DemandFR+I/C
SupplyGB
SupplyGB+I/C
VoLL
VoLL
SupplyFR
PGB
A
B
P’GB
Remaining price
difference
C
PFR
QGB
.
Exhibit 22
Quantity
D
E
QFR
Q’FR
Quantity
Sources: AER
Sources: Ofgem, project websites, AER
36
5
P’FR
• Producer surplus (blue area). For a given market, this is the total quantity
of electricity supplied by domestic producers times the difference between
the price of electricity and the marginal cost of producing that electricity, as
represented by the domestic supply curve. At a constant quantity of domestic
supply, a fall in electricity price decreases producer surplus in the importing
market (area A in the GB market), while an increase in electricity price increases
it (area D in the French market). At a constant electricity price, an increase in
the quantity of domestic supply (due to increased exports to an interconnected
market) results in welfare creation for producers (area E in the French market).
Note that area D is a direct transfer of welfare from consumers to producers,
while area E represents a welfare creation for producers.
4
• Interconnector rent (red area). For a given amount of interconnection capacity,
this is the total quantity of electricity supplied through the interconnector
(interconnector flow) times the remaining electricity price differential across
the two interconnected markets. This is illustrated by area C in the GB market.
Since an increase in interconnector capacity is normally expected to increase
the interconnector flow but to decrease the price differential, the effects
of an incremental increase in capacity on total interconnector rent can be
ambiguous. It is therefore useful to separate the rent captured by the additional
interconnector (which normally accounts for all the additional interconnector
flow) from that of pre-existing interconnectors (which normally only experience
a fall in the price differential).
4.19 To credibly assess the effects of increased interconnection on the three welfare
categories described above, it is necessary to abstract from the simplified view
where interconnector flows are unidirectional and the effect on prices and
quantities are the same in every time period. In addition, a complete assessment of
the costs and benefits of interconnection must also consider the sizeable subsidy
costs to GB consumers and producers associated with increasing interconnector
capacity. The full range of costs and benefits considered in our analysis can thus
be summarised under seven key welfare categories.
• GB consumer cost savings. This is the reduction (or increase) in cost to GB
consumers due to changes in the domestic wholesale electricity price that result
from the introduction of a new interconnector (corresponding to areas A and B
in Exhibit 22). This category also includes changes in total consumer expenditure
under CfD and the Capacity Mechanism (“CM”).
37
4
• GB producer profit reductions. This is the reduction (or increase) in total profits
earned by GB electricity generators measured by the change in electricity
revenue that results from a new interconnector addition minus the change
in operating costs (corresponding to area A in Exhibit 22). This category also
includes changes in total revenue under CfD and CM.
• Proposed interconnector profits. This is the revenue that the proposed
interconnector is expected to earn through subsidies and the sale of electricity
less construction and operating costs. It includes both the direct rent that the
interconnector can capture from arbitraging between markets (corresponding
to area C in Exhibit 22) and any payments received (or made) under Ofgem’s
dedicated cap-and-floor regime for interconnectors, as well as CM revenues.
Interconnector profits are accounted for at 50% of their full value to reflect the
sharing of costs and revenues across the two interconnected markets.
• Other interconnector profit cannibalisation. This is the reduction in arbitrage
rent and subsidy receipts that pre-existing interconnectors suffer as a result
of increased competition with the new interconnector and a smaller price
difference between the interconnected markets.
• Network charges exemption. This is the impact on GB welfare of exempting
interconnectors from the network charges (TNUoS, BSUoS, and transmission
losses) that domestic generators have to pay. It is estimated as the sum of the
network charges that the proposed interconnector would pay if it were treated
as a generator. Hence, it represents the welfare lost as a result of the proposed
interconnector replacing marginal generators that are liable for these charges.
• CPS exemption. This is the welfare impact of exempting interconnectors from
paying CPS charges. It is estimated as the sum of the foregone CPS revenue
that the proposed interconnector would pay if it were not thus exempt plus the
carbon impact of increased interconnector flows, valued at the carbon price
faced by domestic generators.
38
• Cap-and-floor expenditure. This is the value of the total expected expenditure by
GB consumers on Ofgem’s dedicated cap-and-floor regime for interconnectors.
Depending on whether interconnectors pay more than they receive under this
scheme, this value can be either positive or negative.
4.20 In addition to these seven welfare categories, there are other possible costs and
benefits of interconnection that were not considered. An exhaustive exploration of
these would be essential to a final appraisal of particular interconnector projects.
This would likely involve comparing the expected system operability benefits of
additional interconnectors with the foregone system benefits of the dispatchable
thermal plants that are displaced by them. Interconnectors could potentially provide
new types of ancillary services in the future, as well as other system operability
benefits associated with linking interconnectors to particularly underserved parts
of the GB network24 . National Grid has estimated the net present value of these
benefits at over £600 million for a new 1 GW interconnector with France (IFA2),
which is also the number that Ofgem applied in the relevant IPA 25 . However,
National Grid’s methodology did not account for the foregone system benefits
of displaced domestic generation, which can also provide a range of important
balancing and ancillary services that improve system operability. There is not yet any
convincing evidence to suggest that the value of these lost benefits is any smaller
than what interconnectors can provide, especially given that interconnectors are
not expected to participate in the balancing market.
4
4.21 Aurora’s analysis shows that the first two of the seven assessed welfare categories
– consumer cost savings and producer profit reductions – are most affected by
additional interconnection between GB and each candidate interconnected market.
Each 1 GW of interconnection capacity induces a significant welfare transfer
from domestic producers to domestic consumers, and this effect is particularly
pronounced in the case of additional interconnection with Norway, France, and
Belgium (Exhibit 23).
4.22 This is principally due to the downward pressure on GB wholesale prices that
increased interconnection with these countries would cause. Lower prices also
result in additional welfare creation for consumers (area B in Exhibit 22), which
leads to the increase in total consumer surplus being greater than the decrease in
total producer surplus in the GB market.
24 Benefits of Interconnectors to GB Transmission System, December 2014, National Grid Electricity
Transmission.
25 SO Submission to Cap and Floor, December 2014, National Grid Electricity Transmission. Also quoted
in Cap and floor regime: Initial Project Assessment of the FAB Link, IFA2, Viking Link and Greenlink
interconnectors, March 2015, Ofgem.
39
Exhibit 23
4
Welfare impact of an additional 1 GW interconnector added to the “Current IC” scenario in 2020 (PV2020
£bn at discount rate of 3.5%, 2014)
Excluding costs of subsidies
Including costs of subsidies
6
6
4
4
2
0
0.2
1.1
0.5
0.8
0.2
2
0
-2
-2
-4
-4
-6
FRA
NOR
Consumers
Producers
DEN
BEL
IRE
Other interconnectors
Proposed interconnector
-6
-0.9
FRA
0.1
NOR
-0.7
DEN
Network charges exemption
CPS exemption
-0.2
BEL
-0.8
IRE
Cap-and-floor
Total GB
Exhibit 23
Notes: 1. Includes TNUoS, BSUoS and losses exemptions. 2. Assumes all projects are delivered under the capand-floor regime, with cost structures, caps, and floors broadly corresponding to the actual projects of the
corresponding
for cap-and-floor
by
Ofgem.
3. Interconnector
welfare
assumed
to be tosplit
Notes: 1. Includes TNUoS,countries
BSUoS and lossesapproved
exemptions. 2. Assumes
all projects are delivered
under
the cap-and-floor
regime, with cost structures,
caps, and is
floors
broadly corresponding
the
actual projects of the corresponding countries approved for cap-and-floor by Ofgem. 3. Interconnector welfare is assumed to be split on a 50-50 basis between GB and the interconnected market.
on a 50-50 basis between GB and the interconnected market. Sources: Ofgem, AER
Sources: Ofgem, AER,
18
4.23 In addition, the profit for proposed interconnectors is estimated to outweigh
the profit reductions for existing interconnectors in every case that Aurora has
modelled. On the basis of these two findings alone, additional interconnection can
be expected to increase overall net welfare in the GB market, as illustrated on the
left-hand side of Exhibit 23.
4.25 From the consumers’ point of view, the remaining interconnector projects that fail
to increase net welfare may still look attractive in that they redistribute welfare
from producers to consumers, but the large subsidy costs mean that they are
inefficient compared to alternative redistributive mechanisms that could achieve
the same welfare transfer at lower cost.
40
4.24 Giving equal consideration to each of the seven welfare categories, including
subsidy costs, Aurora’s analysis finds that only an interconnection with Norway
increases GB net welfare, while interconnection with other countries decreases
GB welfare (right-hand side of Exhibit 23). This result is driven principally by the
large welfare cost associated with network charge exemptions for interconnectors,
which accounts for more than half the total subsidy cost of all projects. The overall
subsidy costs are similar for all projects, but despite this, the expected profits for
the Norwegian interconnector are large enough to make the project positive in
net welfare terms.
APPENDIX
AAPPENDIX
AURORA’S MODELS
A.1 The analysis for this report is underpinned by the Aurora Energy Research
Electricity System models for Great Britain (“AER-ES GB”) and Europe (“AERES EU”). These models, which were independently developed by Aurora Energy
Research, are market-leading dispatch models used by many major private and
public sector participants in the GB and European power markets to address
strategy, policy, and finance issues.
A
A.2 Given a set of assumptions around interconnector buildout, Aurora’s models
dynamically estimate expected interconnector flows and their impacts on regional
electricity prices. They estimate the flow of electricity on the interconnector based
on the expected half-hourly price differential between GB and the interconnected
market.
AER-ES GB description
A.3 AER-ES GB is a dynamic dispatch model built to emulate the GB power sector
in half-hourly granularity. The model contains a fully specified Capacity Market
module that iteratively finds the economically consistent capacity contract
allocations throughout the coming decades, and the Capacity Market prices
needed to trigger the required investments in generation capacity, subject to an
exogenously given level of supply security.
A.4 Key structural features of the AER-ES GB model include:
• dynamic dispatch of plant, considering ramping costs and rate restrictions, and
stochastic availability of plants and individual generators;
• emulating the entire GB grid, simulating more than 100 plants at an individual
level at half-hourly granularity;
• detailed modelling of Capacity Market mechanism from 2018 onwards,
replicating the market policies as they currently stand;
• financial module to capture investment decisions. Plant mothball, de-mothball,
retire and are built endogenously according to their short- and longer-run
economic prospects in terms of NPV financial returns or direct government
contracting;
• endogenous interconnector flows according to estimated gradient between
domestic and foreign electricity spot prices;
41
APPENDIX
A
• endogenous demand adapting to both economic growth and electricity prices.
In scenarios with higher electricity prices, demand tends to be lower; higher
GDP growth tends to increase power consumption; and
• spatial aspects of the transmission grid and fuel transport costs.
A.5 Key elements of the AER-ES GB parameterisation include:
• plant characteristics such as efficiencies, ramping costs, and rate restrictions
calibrated using historic data since 2005;
• while we draw on historical consumption outturn data to reflect demand
patterns, demand projections incorporate future behavioural change and load
shifting as a consequence of the adoption of new technologies;
• input fuel price projections based on forecasts from the AER-GLO model, a
fully specified global computational general equilibrium model developed by
Aurora Energy Research;
• econometrically estimated uplift function, calibrated based on four years’ worth
of generation and spot price data; and
• stochastic wind calibrated to historic output both across and within plant to get
an accurate picture of performance characteristics of the entire GB wind fleet.
A.6 Furthermore , the medium-term outlook presented here relies on a fully specified
set of policies. The central policy views adopted are developed by Aurora experts
with the engagement of group members. For the purpose of this report, the model
is run in a rational expectations mode, resulting in internally consistent views and
decisions by all actors of the market.
AER-ES EU description
A.8 The Aurora baseline parameterisation relies on a fully specified set of policies.
The central policy views adopted for continental Europe are developed with our
advisors and board members such as Professor Andreas Loeschel and Professor
Dieter Helm and with the engagement of Aurora’s subscription group members.
42
A.7 AER-ES EU is a dynamic dispatch model built to emulate the European power
sectors in hourly granularity. Key features include endogenous capacity additions,
including fully specified scarcity value, endogenous interconnector flows, detailed
country-level power system modules, and integration with AER-ES GB.
APPENDIX
A.9 The modelling framework and parameterisation are described in detail below.
A.10 Key structural features of AER-ES EU include:
A
• dynamic dispatch of plant, considering ramping costs and rate restrictions, and
stochastic availability of plants and individual generators;
• endogenous interconnector flows according to estimated gradient between
domestic and foreign electricity spot prices;
• endogenous demand adapting to both economic growth and electricity prices.
In scenarios with higher electricity prices, demand tends to be lower; higher
GDP growth tends to increase power consumption;
• complete plant-level emulation of selected grids, simulating plants at an individual
level at hourly granularity, including spot and day-ahead prices;
• financial module to capture investment decisions. Plant mothballing,
de-mothballing, retirements, and refurbishments are determined endogenously
according to their short- and longer-run economic prospects in terms of NPV
financial returns;
• industry and district heat demand driven load profiles of heat- and electricityled CHP plants; and
• spatial aspects of the transmission grid and fuel transport costs.
A.11 Key elements of the AER-ES EU baseline parameterisation are:
• plant characteristics such as efficiencies, ramping costs, and rate restrictions
calibrated using historic data since 2005;
• while we draw on historical consumption outturn data to reflect demand
patterns, demand projections incorporate future behavioural change and load
shifting as a consequence of the adoption of new technologies;
• econometrically estimated uplift function, calibrated based on two years’ worth
of generation and spot price data; and
• stochastic wind calibrated to historic output both across and within plant to get
an accurate picture of performance characteristics.
43
APPENDIX
A
FUEL AND CARBON PRICE ASSUMPTIONS
A.12 The assumptions that underpin the analysis presented in this report are
consistent with Aurora’s quarterly Power Market Forecast for the GB market
(October 2015). For a detailed and exhaustive overview of these assumptions,
please contact Aurora at [email protected] to obtain a copy of the latest forecast
report.
Carbon price assumptions
Assumption 1. GB carbon price trajectory
A.13 In our modelling, we assume that the Carbon Price Support (“CPS”) freeze will
last until 2019/20, as currently legislated. Beyond 2020, we assume that the CPS
will be adjusted year by year to achieve the government’s target carbon price
trajectory (Carbon Price Floor – “CPF”), taking into account the evolution of the
European price of carbon – the EU ETS allowance (“EUA”). During this period, we
assume the carbon price trajectory will rise from the level of £22/tonne in 2020
to £40/tonne in 2040 26 .
A.14 Exhibit 26 summarises our carbon price assumptions. With weak EUA prices and
the UK’s ambition to lead the EU’s decarbonisation effort, we forecast a policydriven GB carbon price that is above the price of European emission allowances.
However, we also disaggregate our overall carbon price into EUA and CPS outlooks
and report our official EUA forecast separately (see below).
44
26 We do not specify the measure of these values contributed by the CPS because we assume that it is adjusted
accordingly to adhere to these targets. Our implicit assumption is that the EUAs prices do not exceed this
trajectory.
APPENDIX
Exhibit 26
A
AER carbon price (£/tonne, 2014)
Total carbon price (Carbon Price Floor)
50
Carbon Price Support
EU ETS allowance
45
40
35
30
25
20
36
34 35
32 33
31
30
28 29
27 28
26
25
23 23 23 22 22 23 24
21
15
10
5
0
2015
Exhibit 26
Source:
AER
2020
2025
2030
2035
2040
Source: AER
Assumption 2. EU ETS allowance price trajectory
28
A.15 In our modelling of the EUA prices, we account for recent policy developments,
including 2030 targets for decarbonisation, renewables deployment, and efficiency
improvements, as well as tightening of emission caps under Phase IV of the ETS
and the introduction of the Market Stability Reserve.
A.16 To produce our internal EUA forecast, we employ a hybrid modelling approach
that links our European power dispatch model AER-ES EU and our global general
equilibrium model AER-GLO. The hybrid model solves for the price of carbon
required to achieve a given carbon emissions cap in each year. The combination
of a general equilibrium model that captures all economic activity and a power
dispatch model captures the detailed mechanics of fuel substitution in the power
sector at an hourly resolution, which is critically important for the carbon price
trajectory. For details on this approach, please refer to the Appendix of our report
Coal-to-gas switching in Europe27.
27 Coal-to-gas switching in Europe: Policy levers, winners and losers, global impact, July 2015, Aurora Energy
Research.
45
APPENDIX
A
A.17 Broadly, our ETS forecast is based on modelling the carbon price required to reach
the 2030 EU emissions target (40% carbon reduction relative to 1990 levels) in
combination with other carbon reduction policies.
A.18 First, to establish a benchmark, we model the carbon price that would result if it
were the only policy instrument employed in the ETS sectors to reach the 2030
target.
A.19 Second, we assume non-price policies (most notably mandated coal closures,
efficiency standards, and renewable subsidies) to share the load of carbon
reductions, as practised in recent years by EU member states. This lowers the
ETS price required for the 2030 target.
A.20 Third, due to uncertainty about the contribution from non-price policies within
the ETS sectors, we allow the EU to breach its cap by 1-2% in 2030. Based on our
research and market consultations, we view this as a more realistic outcome than
a very steep increase in the carbon price in the late 2020s.
A.21 Fourth, post-2030, we assume emission caps continue decreasing at the Phase IV
pace of 2.2% per annum, with efficiency improvements and renewable deployment
achieving their pre-2030 rate.
A.22 The resulting ETS allowance price forecast is broadly flat until 2020 and then
increases steeply during Phase IV, reaching €29/tCO2 in 2030 and €39/tCO2
in 2035. We expect relatively little impact from “back-loading” in Phase III of
the EU-ETS – the postponement of the auction of 900 million allowances until
2019/2020.
Fuel prices assumptions
A.24 The Global Energy Markets Modelling team at Aurora produces regular baseline
fuel prices forecasts, using our global general equilibrium model (“AER-GLO”).
The model represents the economies of 129 countries, each broken down into
57 sectors. By using a general equilibrium model, which describes the interactions
between sectors and countries in great detail, we capture the structural evolution
46
A.23 Fuel prices are the single most important driver of electricity market outcomes.
Accurate forecasts for trends in fuel prices are therefore of paramount importance
for electricity market modelling.
APPENDIX
of the economy in response to changes in demand. A general equilibrium approach
offers a substantial advantage over partial equilibrium approaches, which tend
to rely on exogenous growth patterns, locking the structure of the economy into
past trends. On the supply side, we adopt a detailed dynamic resource extraction
module, which is calibrated to our global extraction cost database. Aurora’s
long-term commodity price forecasts are explained in substantial detail in our
annual Global Energy Market Forecast (December 2015).
A
A.25 The fuel price forecast used for this report includes the following key
projections (all in real 2014 terms):
• The natural gas price in Europe remains broadly flat over the next 10 years
at an average level of £4.9/MMBtu, driven by steadily increasing global LNG
availability mainly from the US and Australia; after that, prices return to their
long-term upward trajectory, reaching £5.9/MMBtu by 2040. The upward trend
is a result of the decline in quality of gas fields more than offsetting technological
improvements in extraction – a historically observed relationship
• The coal price increases slightly over the next 15 years and plateaus afterwards
at long-term value of approximately £42/tonne; the initial increase is mainly
driven by the return to Aurora’s view on the current levelised cost of extraction.
This follows a period of low prices caused by oversupply following China’s
demand boom and subsequent slowdown in consumption
A.26 We use the gas and coal price forecast produced by AER-GLO throughout this
report, which are illustrated in Exhibit 27 and
A.27 Exhibit 28. However, in the initial periods our assumed prices follow the latest
available forward curves and over time converge to trajectories defined by the
market fundamentals captured by AER-GLO.
47
APPENDIX
Exhibit 27
A
AER gas price (£/MMBtu, 2014)
6
5
4
3
2
1
0
2015
Exhibit 27 28
Exhibit
Source:
2020
2025
2030
2035
2040
Source: AER
26
AER
AER coal price (£/tonne, 2014)
45
40
35
30
25
20
15
10
0
2015
Exhibit 28
Source:
48
2020
2025
2030
2035
2040
Source: AER
AER
27
5
FOR FURTHER INFORMATION...
The analysis in this report is based on Aurora’s standard market forecast and set of
assumptions. For a complete description of the input assumptions and other aspects of
the market forecast not included here, please contact Aurora at [email protected] to
obtain a copy of our latest GB Power Market Forecast report.
AURORA ENERGY RESEARCH
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UNITED KINGDOM
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This document is provided “as is” for your information only,
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is given by Aurora Energy Research Limited (“Aurora”),
its directors, employees, agents or affiliates (together its
“Associates”) as to its accuracy, reliability, or completeness.
Aurora and its Associates assume no responsibility, and
accept no liability for, any loss arising out of your use of
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information contained in this document reflects our
beliefs, assumptions, intentions, and expectations as of
the date of this document and is subject to change. Aurora
assumes no obligation, and does not intend, to update this
information.
variations of these words or other similar expressions
are intended to identify forward-looking statements and
information. Actual results may differ materially from the
expectations expressed or implied in the forward-looking
statements as a result of known and unknown risks and
uncertainties. Known risks and uncertainties include
but are not limited to risks associated with commodity
markets, technology, contractual risks, creditworthiness
of customers, performance of suppliers and management
of plant and personnel; risk associated with financial
factors such as volatility in exchange rates, increases in
interest rates, restrictions on access to capital, and swings
in global financial markets; risks associated with domestic
and foreign government regulation, including export
controls and economic sanctions; and other risks, including
litigation. This list of important factors is not exhaustive.
FORWARD LOOKING STATEMENTS
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without the prior written consent of Aurora.
© 2016 AURORA ENERGY RESEARCH LIMITED.
REF: DIRV1-0216

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