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Integration of Variable Renewables
Volume I: Main Report
January 2015
IEA-RETD
326641 TRD EFR 5 e
Vol I: Main report
28 November 2014
Integration of Variable Renewables
Volume I: Main Report
Integration of Variable Renewables
Volume I: Main Report
January 2015
IEA-RETD
Mott MacDonald, Victory House, Trafalgar Place, Brighton BN1 4FY, United Kingdom
T +44 (0)1273 365 000 F +44(0) 1273 365 100 W www.mottmac.com
326641/TRD/EFR/5/e January 2015 Vol I: Main report
Integration of Variable Renewables Volume I: Main Report
Revision Date Originator Checker Approver Description
A 30 May 2014 Andrew Conway Guy Doyle David Holding Working Document
B 11 July 2014 Andrew Conway Guy Doyle David Holding Draft Final Report
C 2 September 2014 Andrew Conway Guy Doyle David Holding Final Report
D
15 October 2014 Andrew Conway Guy Doyle David Holding Final Report v2 awaiting external review
E 28 November 2014 Andrew Conway Guy Doyle David Holding Final report for publication
Issue and revision record
Information Class: Standard
This document is issued for the party which commissioned it and for specific purposes connected with the above-captioned project only. It should not be relied upon by any other party or used for any other purpose.
We accept no responsibility for the consequences of this document being relied upon by any other party, or being used for any other purpose, or containing any error or omission which is due to an error or omission in data supplied to us by other parties.
This document contains confidential information and proprietary intellectual property. It should not be shown to other parties without consent from us and from the party which commissioned it.
This publication should be cited as: IEA-RETD (2015), Integration of Variable Renewables (RE-INTEGRATION), [A.Conway; Mott MacDonald] IEA Implementing Agreement for Renewable Energy Technology Deployment (IEA-RETD), Utrecht, 2015.
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Chapter Title Page
No table of contents entries found.
Figures
Figure 1.1: System characteristics influence on the nature of the VRE integration challenge __________________ v Figure 1.1: World map of jurisdictions in the study ___________________________________________________ 2 Figure 2.1: Approach _________________________________________________________________________ 3 Figure 3.1: Danish wind and net load variability _____________________________________________________ 7 Figure 4.1: Smoothing by aggregating: Wind in Germany ____________________________________________ 13 Figure 4.2: PV generation and load in Western Electricity Coordinating Council (WECC) ____________________ 14 Figure 4.3: VRE penetration – capacity as a percent of peak demand (2013/14) __________________________ 15 Figure 4.4: Level and type of interconnection ______________________________________________________ 16 Figure 4.5: Storage technologies _______________________________________________________________ 18 Figure 4.6: Non-VRE capacity as a percentage of peak demand _______________________________________ 19 Figure 5.1: The “Duck Curve” – increased ramping requirements in California ____________________________ 23 Figure 6.1: The eight frame conditions ___________________________________________________________ 29 Figure 6.2: Regulating reserve requirement in ERCOT ______________________________________________ 31 Figure 6.3: Alberta wind speed distribution Geographical deployment ________________ 33 Figure 6.4: Average pool price captured by northern and southern wind farm _____________________________ 34 Figure 6.5: Oversupply in Ontario leading to nuclear shutdown ________________________________________ 35 Figure 6.6: Dispatch of wind allows for economic wind curtailment in Ontario _____________________________ 35 Figure 6.7: Annual operating cost savings ($million) due to implementation of state of the art forecasting _______ 36 Figure 6.8: Use of frequency reserves (system services) in Spain plotted against installed wind power capacity __ 40 Figure 6.9: Use of secondary and tertiary reserves before and after TSO collaboration _____________________ 41 Figure 6.10: System service reform in ERCOT______________________________________________________ 43 Figure 6.11: ERCOT reform from zonal pricing to Locational Marginal Pricing _____________________________ 46 Figure 6.12: ERCOT zonal Vs nodal (LMP) grid representation _________________________________________ 47 Figure 6.13: European market coupling aims _______________________________________________________ 49 Figure 6.14: Alberta (left) + CAISO (right) _________________________________________________________ 52 Figure 6.15: ERCOT (left) + Ontario (right)_________________________________________________________ 53 Figure 6.16: Denmark (left) + Germany (right) ______________________________________________________ 53 Figure 6.17: Great Britain (left) + Ireland (right) _____________________________________________________ 53 Figure 6.18: Spain ___________________________________________________________________________ 54 Figure 7.1: Context as defined by nature of interconnection and access to internal flexibility _________________ 59 Figure 7.2: Approaches to VRE integration under different contexts ____________________________________ 60
Tables
Table 1.1: Importance of integration measures under different contexts __________________________________ xi Table 2.1: Start years for each jurisdiction ________________________________________________________ 4 Table 2.2: Summary of responses to questionnaires and completion of interviews _________________________ 5 Table 3.1: Integration measures to address each challenge for policymakers ____________________________ 10 Table 4.1: Flexibility of dispatchable generation technologies _________________________________________ 17 Table 4.2: Key characteristics of the case study jurisdictions _________________________________________ 20 Table 5.1: Perception of the severity of challenges _________________________________________________ 26 Table 6.1: Price caps and negative pricing _______________________________________________________ 30 Table 6.2: VRE incentives and dispatch _________________________________________________________ 32 Table 6.3: Use of forecasting in the case study regions _____________________________________________ 37 Table 6.4: Grid code comparison in case study jurisdictions __________________________________________ 38 Table 6.5: System services market _____________________________________________________________ 40
Contents
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Table 6.6: Grid representation in the market ______________________________________________________ 45 Table 6.7: Interconnector management in case study jurisdictions _____________________________________ 48 Table 6.8: Regulatory incentives on system operators ______________________________________________ 51 Table 6.9: National Grid wind forecast error targets ________________________________________________ 51 Table 6.10: Key focus of jurisdictions ____________________________________________________________ 54 Table 6.11: List of measures and challenges ______________________________________________________ 55 Table 7.1: Importance of integration measures under different contexts _________________________________ 65 Table A.1: Scoring mechanism for frame-conditions ________________________________________________ 73
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The integration of increasing levels of Variable Renewable Energy (VRE) is one of the
most important challenges facing modern advanced power systems today. New policy
tools will need to be harnessed in order to successfully integrate high levels of VRE.
Mott MacDonald was commissioned by the IEA-RETD to investigate the influence of
different jurisdictions’ context on the integration challenge, addressing three research
questions:
What are typical country specific factors that determine the choice of integration
measures?
Different countries may have different preferences in terms of integration. Based on
case studies, what can be concluded about which options are applicable and effective
in which context?
What general lessons might be drawn by countries with similar underlying
characteristics?
This report (Volume I) outlines the overall approach taken, some of the background
behind the study and key findings from the more detailed analysis within the case
studies. More detailed information relating to each jurisdiction can be found within
Volume II – Case Studies. The reports are aimed at policy makers and those with some
or little technical knowledge – the language and content of both reports reflects this
assumption about the level of understanding of the reader.
Integration policies for VRE aim to create the conditions in a power system such that
system costs (due to VRE) are reduced or that the power system can accommodate
higher levels of VRE penetration. Integration policies are not about directly increasing
deployment through support policies, though this should be an indirect result of the
policy. The focus is on measures that can change the market conditions (which policy
makers in market based jurisdictions can do), which will give rise to short term changes
in operations and long term changes in infrastructure.
Our analysis is based on a number of case studies agreed by Mott MacDonald and the
IEA-RETD. All the case studies except one are related to deregulated markets.
Hokkaido, which is a vertically integrated system, is the notable exception. The case
study jurisdictions are shown on the map:
Executive Summary
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VRE technologies are fundamentally different from conventional technologies.
Generation from VRE is:
Variable
Uncertain
Non-synchronous
Location specific
Modular
Zero fuel cost
These attributes present a number of challenges to system operators who are seeing an
increase of VRE on their systems and who are charged with ensuring their power system
remain stable and resilient. These issues are discussed in Chapter 5. All network users,
from connected generators to consumers, may also be impacted, so therefore this has a
broader energy policy impact.
Ontario
CAISO
Alberta
ERCOT
Ireland
Great Britain
Spain
Denmark
GermanyHokkaido
AlbertaOntario
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Our work identifies four main challenges for policy makers in addressing VRE integration:
1. Ensuring VRE is deployed in a way that makes the most of VRE generation while
reducing its negative system impacts.
2. Introducing market arrangements and operational practices which make the most of
the current installed flexibility. Flexibility is the capability of generation plant,
connected load and storage facilities to adjust operations/provide services to
accommodate VRE. This flexibility is the ability to vary output between its minimum
and maximum output, start up and shut down characteristics and its dynamic
response over short timeframes.
3. Creating an incentive environment that encourages investment in the required
amount of flexibility, where flexibility comes from generation, storage and demand
side response.
4. Making the most of scarce grid resources (in terms of capability to transport
electricity from producers to load centres in an efficient manner).
Not all the challenges are felt equally across all jurisdictions, due to the context
(characteristics) of the jurisdiction. Characteristics such as the size and portfolio of
VRE, geographical distribution of VRE, type and level of interconnection and the access
to flexibility determine the nature of the integration challenge a jurisdiction will face.
Additionally, the regulatory arrangements of a jurisdiction (for example, the use of
markets, separation of utility functions and operations) will influence the types of
measures which can be implemented.
The table below illustrates how we have classified the various jurisdictions based on key
characteristics.
country VRE portfolio Geographical
distribution of VRE Interconnection Flexibility
Alberta
California
ERCOT
(2 percent of peak demand)
Ontario
Denmark*
Germany
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country VRE portfolio Geographical
distribution of VRE Interconnection Flexibility
Great Britain
(8 percent of peak demand)
Ireland
(11 percent of peak demand)
Spain
Hokkaido
(10 percent of peak demand)
Source: Respective sources detailed in the case studies and Mott MacDonald
Key conclusions
One clear overall conclusion is that context matters in shaping the choice of measures,
and that this influence can be seen through four dimensions:
Level of interconnection
Access to internal flexibility
Size and nature of VRE portfolio
Spatial pattern of VRE
The first two dimensions relate to the characteristics of the system itself and so define
the foundation, with the VRE size and spatial aspects sitting on top, as characteristics of
the VRE deployed.
High wind and solar
High wind
Mid VRE penetration
Low VRE penetration
Strongly interconnected
Weakly interconnected
Synchronously Independent
High flexibility
Low flexibility
Well distributed
Mostly distributed
High concentration in few areas
Mostly in one area
Mid flexibility
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The first two dimensions can be plotted on a two-by-two matrix in which one can view the
position of any jurisdiction and the nature of challenges it is likely to face – see Figure
1.1. Jurisdictions in the top right box face the most challenging situation – needing to
consider all measures, but there will be a limited scope and value in measures
associated with interconnector management. Ireland is the closest example of such a
context in the jurisdictions considered in this study, although it has reasonable internal
flexible resource. It has also recently increased its interconnection capacity, but further
increases are a long term measure as indicated by the dashed left pointing arrow. In
contrast, jurisdictions in the bottom left box will face a less onerous challenge; they only
need to implement more straightforward measures, including interconnector access
items. Denmark is a good example of such a jurisdiction.
Figure 1.1: System characteristics influence on the nature of the VRE integration
challenge
Source: Mott MacDonald
The bold blue arrows in the figure show the main policy aim for jurisdictions in the upper
boxes: all will have a greater or lesser incentive to increase internal flexibility. The right-
to-left (dashed) arrow in the centre (mentioned above) reflects a long term objective to
increase interconnector capacity (although there is in practice a practical limit to
connecting some synchronously islanded systems).
D
Weakly connected
High internalflexibility
Well interconnected
Low internalflexibility
Easy
Challenging
Will need to consider all measures
Implement easy measures including interconnector access
Long termPossibility
Polic
y ai
m
Polic
y ai
m
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The high losses involved in subsea HVAC cables make such interconnectors unviable,
so HVDC is preferred and while this brings benefits for wider VRE aggregation and
sharing flexibility, this does not provide synchronous coupling, which may be an issue for
island systems.
It should also be noted that interconnection with other jurisdictions will only bring
significant benefits if there are complimentary flexible resources.
As one would expect, the magnitude of the VRE integration challenge and the choice of
measures applied is seen to depend on the size and nature of the VRE portfolio.
Jurisdictions with higher levels of VRE penetration as measured by VRE’s share of
instantaneous load will tend to require a wider range of interventions. And in systems
where wind or solar is predominant there will be different challenges which will call for
different responses.
The influence of the spatial context is more straightforward. Other than building new
network capacity, grid bottlenecks can be addressed by a combination of mechanisms
which put a scarcity price on constraints and so shift dispatch in a way that optimises the
use of limited grid capacity. This could include new operational measures like dynamic
line rating (DLR) and flexible security standards (holding less capacity aside under
certain conditions), both of which make the most of interconnection capacity. In the
longer run, the Locational Marginal Pricing (LMP) prices will provide evidence of the
value of new grid capacity and/or VRE deployment.
Interconnection with other systems
Jurisdictions with higher levels of interconnection tend to use interconnectors as a key
measure for integrating VRE through accessing a much larger market. This allows
access to other systems’ inertial response and flexible resources as well as the pooling
of VRE output (so reducing the variability of overall VRE). A small system with a high
VRE share can therefore “piggyback” on a larger system, assuming this does not itself
have a high VRE share. Denmark, while implementing integration policies, has been able
to take advantage of its location within Europe to successfully integrate a large amount of
VRE.
In contrast, synchronously independent systems (such as Hokkaido, Great Britain and
ERCOT) are developing additional system services in order to remunerate providers of
inertia and fast frequency response to ensure system stability at high levels of VRE.
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Internal flexible resources
Systems with large amount of flexibility have a comparatively easy task of
accommodating high levels of VRE. These jurisdictions tend to focus on ensuring there
are appropriate incentives for flexible resources and that sophisticated forecasting and
scheduling/despatch algorithms are applied so as to reduce reserve and balancing costs.
Jurisdictions which lack adequate access to internal flexibility may suffer problems even
at low VRE penetration levels which may lead to VRE being curtailed as has happened
in Ontario, where there is large tranche of inflexible baseload nuclear and inflexible
hydro. Ontario has introduced a special alert service to allow it to better manage this
situation.
Size and the nature of VRE portfolio
The size and the shape of the VRE portfolio matters, as we discuss below:
Systems which experience high spot shares of VRE in total generation tend to face
greater challenges in terms of ramping and inertia and frequency response. Commonly
applied measures are application of sophisticated forecasting/despatch techniques, and
incentives for provision of flexibility and rules/incentives to encourage system friendly
VRE deployment. Where there are preferential offtake arrangements (whether premiums
or feed-in-tariffs), negative pricing may be required to deter some discretionary
generation and/or encourage uptake via exports, DSM and charging storage. The
alternative is curtailment (which can be indirect or through direct dispatch control).
More generally, it is apparent that as the level of VRE penetration increases to high
levels, the VRE is required to perform more like conventional generation (for example, by
offering system services). Financial support and protection from imbalance penalties is
reduced, dispatch priorities are weakened and full (or near full) compliance with grid
codes is required. Central (SO) dispatch control of wind is another measure that can be
employed to achieve efficient use of VRE.
The mix of VRE matters too, although different jurisdictions response varies depending
on the broader context (level of interconnection and access to internal flexible
resources).
Solar PV tends to have lower visibility than wind to SOs, because it is generally deployed
at much smaller scale and so monitoring and metering requirements are less onerous.
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Jurisdictions with high solar shares are beginning to experience (or are forecasting) high
ramping requirements especially in evenings (when PV output falls and evening load
rises). At the same time a number of jurisdictions (Germany, Spain and Ontario) are also
experiencing reverse power flows during peak solar hours in parts of their distribution
networks which are being addressed by updating control systems and temporary
operational changes. Several jurisdictions (ERCOT, CAISO, Hokkaido and Germany) are
supporting pilot projects for deployment of electricity storage installed at or close to PV
sites. Indeed, some US jurisdictions (most notably California) and Germany are seeing
an emerging consumer led demand for batteries and smart controls for PV.
Spatial aspects
Where deployment of VRE is concentrated geographically and away from the main load
centres this can present a challenge in terms of network congestion. A number of
jurisdictions have had to address this issue. In Texas, ERCOT has replaced a zonal
market arrangement with a nodal one that more clearly identifies the physical
transmission constraints through the more granular pricing. This allows a more efficient
dispatch and provides more refined incentives for transmission owners and generators’
investment. ERCOT has also implemented Competitive Renewable Energy Zones
(CREZ), to channel new investment into preferred areas, which has eased the
transmission challenge. In GB, National Grid is building the first of a pair of offshore
HVDC lines that will enable the export of Scottish wind energy to England, while
Germany has plans for new north-south transmission axis for supplying northern wind
energy to the south and importing solar to the north.
Underlying trends
In addition to these contextual drivers the study has identified a number of trends in the
ways measures are applied that relate to wider technology and market development:
Grid code requirements for VRE are tending to get stricter and in the future could
require synthetic inertia, active power and frequency response and high wind ride
through capabilities. This reflects technical advances and a reduction in costs of
including these capabilities as well as recognition of their value to the SO.
Dispatch is tending to become more sophisticated – jurisdictions are shortening gate
closure and/or dispatch intervals, increasing price caps and introducing negative
pricing in markets. This trend is probably driven by “learning by doing” of SOs, market
operators and regulators; however, it has almost certainly been reinforced by the
increased interest in trading between jurisdictions (in Europe and North America) and
the need to accommodate an increased level of renewables.
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VRE generators are becoming more exposed to market forces by moving towards
market premium as opposed to FiT incentive schemes, requiring VRE dispatch,
exposure to imbalance risk and reducing compensation for curtailment. This should
lead to more system friendly VRE deployment and economic operation of the power
system; however this comes with increased risk for developers and higher associated
development costs. The drivers for this trend for increased exposure to markets are
clearly the increasing penetration of VRE itself and the improvement in their
competitive position.
General lessons and recommendations for policymakers
A number of lessons can be drawn from this study, which can be considered under two
broad categories: general lessons and lessons for jurisdictions with particular
characteristics. Each is considered in turn.
General lessons
1. The deployment patterns/mix of technologies should be considered at an early stage
of VRE deployment in order to mitigate congestion/ reduce swings in net load. The
measures that our study shows to have successfully impacted on deployment
patterns and the mix of technologies include differentiated financial support,
planning (such as the introduction of planning zones seen in Texas) and using
connection rules/charges for different technologies.
2. Build-in grid code measures sooner rather than later. The prudent approach is to
ensure that VRE is built-in with as much grid support functionality as is viable,
without incurring excessive cost.
3. Move to near real time re-dispatch supported by sophisticated forecasts of VRE
output and load. This allows a more efficient scheduling of capacity and reduces the
need to carry operating reserve.
4. Learn from others but do one’s own studies to assess impacts.
5. Co-operate with other jurisdictions. This can take a number of dimensions.
Exploiting the opportunities to trade energy, reserve and balancing services to the
fullest extent is likely to be one of the best ways of integrating VRE where a
jurisdiction has interconnector access to other jurisdictions. International (or cross
jurisdiction) co-operation is clearly essential for new interconnector capacity, and
here mechanisms for benefit sharing and consenting would help in deploying such
assets. Lastly, co-operation on industry codes, such as grid codes can bring benefits
to developers, technology developers and system operators.
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Lessons by characteristics
1. Well-connected countries should focus on interconnector rules and market
harmonisation – this has been successfully demonstrated in Germany and Denmark.
The first priority should be making sure the fullest interconnector capacity is made
available and applying “use it or lose it” rules for capacity allocation. This should be
followed by coupling of day ahead and intraday markets and SO-to-SO co-operation
on balancing, which has been implemented in the GB and Spain.
2. Jurisdictions experiencing chronic grid bottlenecks should consider both operational
measures such as dynamic line rating (and potentially special derogations in security
standards) and market arrangements which explicitly incorporate the spatial
dimension in pricing. A full nodal market, (such as has been established in ERCOT),
is the most economically efficient; however, a zonal market can sometimes also bring
a significant share of the benefits. Both of these spatial market mechanisms will
provide indicators of the value of new transmission capacity.
3. Systems with weak interconnections and especially those with asynchronous links
need to be aware that their challenge will be greater and consider special system
services for inertia and fast frequency response, dynamic reactive power and
emergency response to frequency drops (through DSR and storage) to ensure
adequate flexibility and system resilience. Ireland and EROCT are shortly to
implement special system services for inertia and fast frequency response.
4. Systems with low internal flexibility and weak interconnections need to be aware that
they will face caps on VRE deployment (before curtailment is required) unless they
address these constraints.
5. Systems lacking significant flexibility (due to high shares of nuclear or inflexible
coal/gas/hydro plant) may be forced to choose between curtailing VRE or their
“inflexible” dispatchable plant even at fairly low VRE shares, as has been
demonstrated in Ontario. Exploiting existing Demand Side Response (DSR) and
squeezing the most out of existing interconnectors should be first priorities, although
scope here may be limited. Beyond this, these systems will need to expand storage
(demonstrated in Alberta and Hokkaido), DSR and interconnector capacity. Increasing
flexible generation capacity will only resolve curtailment issues arising from an excess
of inflexible VRE if the inflexible plant is retrofitted or displaced by new flexible plant.
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Detailed listing of measures by context
Table 1.1 provides our assessment of the importance of different VRE measures under a
range of different contexts. The measures are rated on a zero to three star basis, with
three stars being of critical importance. Our assessment is based on the finding of this
study although it is necessarily subjective. It is important to note that our assessment
applies to jurisdictions that are attempting to reach high level shares of VRE. In this
respect, it is important that the process of implementing some of the measures is done
so in a way that does not reduce investment in VRE, especially in the early stages. For
example, we consider market exposure will be important for VRE integration at high
shares of VRE. However, this will increase the risk premium and therefor cost for
developers, and so increasing market exposure may need to be implemented at later
stages of deployment.
Table 1.1: Importance of integration measures under different contexts
Measure Easy Challenging Special circumstances
Well inter-connected/ high flex
Weakly connected/ low flex
Synchronously isolated/ high flex
Synchronously isolated/ low flex
Congested networks
High wind share
High solar share
Dispatch Sophistication
Short programme time units ** ** *** ** ** ***
Short gate closure/re-dispatch times
** *** *** ** ** **
Demand participates in sport market (or ToU pricing)
* ** *** ** ** **
Storage participating in spot market
* ** *** ** ** **
High or uncapped prices across DA, intraday and balancing markets
* ** *** ** ** **
Negative prices in energy market
* ** *** ** ** **
Grid Representation
Zonal market * * *
Locational Marginal Pricing ** **
Grid code
Active power and frequency control
** *** *** *** *** *
High wind ride through ** ** *** *** ***
Reactive power support * ** *** *** *** *
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Measure Easy Challenging Special circumstances
Well inter-connected/ high flex
Weakly connected/ low flex
Synchronously isolated/ high flex
Synchronously isolated/ low flex
Congested networks
High wind share
High solar share
Fault-ride through * ** ** *** *** *** ***
Emulated inertia * ** ** ** **
VRE incentives and dispatch
Increase exposure to energy market
* ** ** *
Increase exposure to imbalance risk
* ** *** *
Reduce compensation for curtailment
* ** * *
Require VRE to dispatch in energy market
* *** * *
Explicitly incentivise geographical distribution of VRE
* * ** *** *** **
Designate renewable zone * ** ** *
Dispatch control of wind * ** *** ** *** *
Interconnector management
Integrate interconnectors into day ahead market
* ** * * *** *** ***
Integrate interconnectors into intraday market
** *** * * *** *** ***
Use interconnectors for balancing
** *** * * *** *** ***
Full market coupling * ** * * ** ** **
Regulator incentives
Explicit incentive mechanisms to achieve system cost and performance targets
* * ** * * *
System services market
Demand as emergency response
* ** *** *** *** ***
Storage as emergency response
* ** *** ** * *
Demand participating in ancillary services
* * *** ** ** **
Storage participating in ancillary services
* *** ** ** **
$
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Measure Easy Challenging Special circumstances
Well inter-connected/ high flex
Weakly connected/ low flex
Synchronously isolated/ high flex
Synchronously isolated/ low flex
Congested networks
High wind share
High solar share
Increase sophistication of system services
* ** ** *** ** ** **
Use of Forecasting (UoF)
Real time monitoring of VRE output
* ** ** *** *** *** ***
Centralised forecasting * ** ** *** *** *** ***
Use of ramping forecasts ** ** *** *** *** ***
Use of rolling forecasts to calculate ancillary service requirements
* ** *** *** *** ***
Source: Mott MacDonald
Suggestions for further work
In conducting this study it became clear that there are numerous measures which policy
makers can take to influence the ability of electricity systems to accommodate increasing
levels of variable renewable energy. This report maps a large number of measures – but
restricts itself to those that can be grouped under one of the eight dimensions of the
frame conditions which cover market and operational rules. We have therefore not
covered policy measures relating to reducing barriers to deployment of VRE and flexible
resources: such as consenting and planning (including stakeholder engagement) and
financial support for investments and technology development. These would have
significant value in developing an extended taxonomy of measures in a way that
identifies who the key agents for implementation are (market operator, system operator,
regulator/government, planning authority, etc.). Other categorisations could also be
considered.
This survey has also revealed the dearth of information on the costs and benefits of
measures for integrating variable renewables. This is not entirely surprising given that
many of the interventions have a wide remit and there are many different agents for
implementation. As mentioned in this report, the direct costs of most interventions are
small as they generally relate to changes in operational practices and market rules, etc.;
although the indirect costs1 on market participants and network users may be more
significant.
1 Indirect costs such as investment in retraining, new systems, operational practice, equipment changes may be borne by participants due to market changes
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The main uncertainty here relates to the benefit side as this is very difficult to determine
given the need to define counterfactuals. All this is an area which deserves more review
and analysis, as this should throw proper light on the effectiveness of measures.
A further area to explore in further studies of measures for integrating VRE is the extent
to which there is a need for some kind of “system architect” for ensuring a properly
integrated approach is applied to VRE integration. This could involve the whole policy
chain from planning and assessment studies, through implementation and monitoring
and evaluation.
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The authors would like to extend their gratitude to the members of the RE-Integration
Project Steering Group: Michael Paunescu (Natural Resources Canada), Darcy Blais
(Natural resources Canada), Yoko Ito (Institute of Energy Economics Japan), Akihiro
Iwata (New Energy and Industrial Technology Development Organization), Yasuyuki
Kowata (New Energy and Industrial Technology Development Organization), Simon
Mueller (International Energy Agency) and Sascha van Rooijen (Operating Agent IEA-
RETD).
The completion of this report would not have been possible without the support and
efforts of the survey respondents, interviewees and external reviewers. Those that have
provided information have been very cooperative and have given valuable insight into a
number of technical / policy matters.
This report relies upon information received through a survey and interviews, and whilst
we have made efforts to verify the information with the source we cannot guarantee the
accuracy of the information presented.
Acknowledgements and Disclaimer
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List of Acronyms
AC Alternating Current
AER Alternative Energy Requirement
AESO Alberta Electricity System Operator
AIES Alberta Interconnected Electricity System
ATC Available Transfer Capacity
BALIT Balancing Inter TSO
BSIS Balancing Services Incentive Schemes
CAISO California Independent System Operator
CCGT Combined Cycle Gas Turbine
CCGT Combined Cycle Gas Turbine
CECRE Centralised Control Centre of Renewable Energy
CfD Contracts for Difference
CHP Combined Heat and Power
CREZ Competitive Renewable Energy Zones
CSP Concentrating Solar Power
CWE Central West Europe
DA Day Ahead
DC Direct Current
DECC Department of Energy and Climate Change
DER Distributed Energy Resources
DLR Dynamic Line Rating
DNO Distribution Network Operators
DSBR Demand Side Balancing Reserve
DSO Distribution System Operators
DSR Demand Side Response
EEX European Energy Exchange
EMCC European Market Coupling Company
EMR Electricity Market Reform
ENTSO-E European Network of Transmission System Operators for Electricity
ERCOT Electricity Reliability Council of Texas
FACTS Flexible Alternating Current Transmission System
FFR Fast Frequency Response
FFRS Fast Frequency Reserve Service
FiP Feed in Premium
FiT Feed in Tariff
FRT Fault Ride Through
GB Great Britain
GCC Grid Control Cooperation
GW Giga Watt
HEPCO Hokkaido Electric Power Company
HRUC Hourly Reliability Unit Commitment
HVAC High Voltage Alternating Current
HVDC High Voltage Direct Current
HWRT High Wind Ride Through
HWSD High Wind Shut Down
IGCC International Grid Control Cooperation
IR Inertial Response
ISO Independent System Operator
ITVC Interim Tight Volume Coupling
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LFC Load Frequency Reserve
LMP Locational Marginal Pricing
LRAS Large Ramp Alert System
LTEP Long Term Energy Plan
MAE Mean Absolute Error
MW Mega Watt
MWh Mega Watt hour
NERC North American Electric Reliability Corporation
NG National Grid
NPCC Northeast Power Coordinating Council
NWE North West Europe
OIESO Ontario Independent Electricity System Operator
PFR Primary Frequency Response
PTC Production Tax Credit
PUCT Public Utility Commission of Texas
PV Photo Voltaic
REE Red Electrica de Espana
REFIT Renewable Energy Feed In Tariff
RfP Request for Proposal
RO Renewables Obligation
RoCoF Rate of Change of Frequency
RPS Renewable Portfolio Standard
RRS Responsive Reserve Service
RRSG Responsive Reserve Service from Generation
RRSL Responsive Reserve Service from Load
RS Regulation Service
SBR Supplemental Balancing Reserve
SCED Security Constrained Economic Dispatch
SEM Single Electricity Market
SEMO Single Electricity Market Operator
SIR System Inertial Response
SIR Synchronous Inertial Response
SNSP System Non Synchronous Penetration
SO System Operator
SONI System Operator of Northern Ireland
SRMC Short Run Marginal Cost
SWPL System Wind Power Limit
TNUoS Transmission Network Use of System
ToU Time of Use
TSO Transmission System Operator
UMIS Uplift Management Scheme
VRE Variable Renewable Energy
WECC Western Electricity Coordinating Council
WEPROG Weather and Energy Prognoses
WPRM Wind Power Ramp Management
WSAT Wind Security Assessment Tool
WTR Wind Technical Rule
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The integration of increasing levels of Variable Renewable Energy (VRE) is one of the most important
challenges facing modern advanced power systems today. Different approaches are being used integrate
VRE. This study investigates how the context of a jurisdiction influences the choice of approach to
integration.
1.1 This report
In 2013, Mott MacDonald was commissioned to undertake a research project for the IEA Renewable
Energy Technology Development into the integration of Variable Renewable Energy (VRE).
The overall objective of the research was to understand how the context of each jurisdiction influences the
measures implemented to integrate VRE and the effectiveness of these measures. The study investigates
the context, challenges and integration measures in a number of different jurisdictions throughout North
America, Western Europe and Japan. The lessons learnt from this study are built around a case study
approach based on desktop research, questionnaires and interviews with system operators and policy
makers. The case studies are detailed in Volume II.
1.2 Scope of the report
Our three main research questions are:
1. What are typical country specific factors that determine the choice of integration measures?
2. Different countries may have different preferences in terms of integration. Based on case studies,
what can be concluded about which options are applicable and effective in which context?
3. What general lessons might be drawn by countries with similar underlying characteristics?
1.3 Jurisdictions
The jurisdictions for this study have been agreed jointly between the IEA-RETD and Mott MacDonald. They
have been selected to give a broad cross-section of jurisdictions which have different contextual
characteristics, levels of VRE penetration and as a result have implemented a range of policies to address
VRE integration (see Figure 1.1). The jurisdictions selected are representative of economically developed
and liberalised power systems. Hokkaido is the only jurisdiction in the study that has a vertically integrate
monopoly utility, whereas the others are market based systems. This influences the types of measures that
can be implemented – this study has focused on the measures available to policy makers in market based
jurisdictions. The focus is on measures that can change the market conditions (which policy makers in
market based jurisdictions can do), which will give rise to short term changes in operations and long term
changes in infrastructure.
1 Introduction
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Figure 1.1: World map of jurisdictions in the study
Source: Mott MacDonald
Note: California Independent System Operator (CAISO) operates the majority of the power grid in the state
of California. Electricity Reliability Council of Texas (ERCOT) operates the majority of the power grid in the
state of Texas. Data and policies in these reports refer to CAISO and ERCOT.
1.4 Structure of the report
The structure of the report is as follows: section 2 details our Approach. Section 3 explains the Challenges
for Policy Makers. Section 4 illustrates the Characteristics that Influence Integration and groups
jurisdictions according to their characteristics. Section 5 describes the System Impacts of VRE and how
these are manifesting in the case studies. Section 6 details the Integration Measures that are being used in
each of the case study regions and analyses how the choices of measures have been influenced by
context. Section 7 provides the key Conclusions and Recommendations for policy makers.
Ontario
CAISO
Alberta
ERCOT
Ireland
Great Britain
Spain
Denmark
GermanyHokkaido
AlbertaOntario
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Our approach to answering the key research questions has been threefold: a literature review, a detailed
survey of system operators and a series of interviews with system operators and policy makers. We have
used our professional judgement and experience to interpret the significant volumes of information
received and assesses the impacts of the measures adopted by the various jurisdictions (see Figure 2.1).
Figure 2.1: Approach
Source: Mott MacDonald
2.1 Literature review
The literature review scoped out the subject and informed the conceptual approach to the research
questions. It informed the categorisation of the integration measures into eight ‘frame-conditions’ and the
integration challenge into six discrete challenges. The review identified gaps in the literature on how the
context of a jurisdiction influences the challenges and the applicability of integrations measures.
From the literature review, we developed a detailed questionnaire to survey the selected case study
jurisdictions.
2.2 Survey
We conducted a survey of system operators in the case study jurisdictions using a detailed questionnaire.
Given the complexity of the subject and the significant diversity of the jurisdictions, it was not possible to
devise a very detailed set of questions that would have been applicable to each area. As such the
questionnaire requested information on three key areas:
Perceived challenges;
Integration measures; and
Measures timeline.
1. Literature review
2. Survey
3. Interviews
Analysis and professional judgement
Key messages , conclusions &
recommendations
2 Approach
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2.2.1 Perceived challenges
The challenges section defined the six discrete integration challenges and asked the system operators to
rate the severity of each challenge on a scale of 1 to 5. All survey participants except CAISO (California)
had responded to this section of the questionnaire. OIESO (Ontario) did not rate the challenges, but
provided discussion on each, from which we inferred ratings. EirGrid (Ireland) provided a rating for 2014,
2018 and 2022. For the purposes of comparison, we used the 2014 values. In most cases, respondents
reported that the ratings were made by consensus judgements from a number of experts within each SO.
2.2.2 Integration measures
The integration measures section was a detailed questionnaire on all of the aspects of whether and how
integration measures had been applied in the jurisdiction. The questionnaire requested information about
measures for both current year and a defined start year. The start year was different for each jurisdiction
and was chosen based on the year of introduction of a major policy drive towards developing VRE (see
Table 2.1). The purpose of the start year was to provide us with a defined period that we could use to
assess the changes in the jurisdiction.
Table 2.1: Start years for each jurisdiction
Year to start assessment
period Policy introduced
Alberta (Canada)*; 2003 AESO and spot market established
California (USA); 2002 Renewable Portfolio Standard -- California
Texas (ERCOT, USA); 1999 Renewable Portfolio Standard -- Texas
Ontario (Canada); 2006 Ontario Renewable Energy Standard Offer Programme (RESOP)
Denmark; 2000 Legislation on Electricity Favourable to Renewables (Electricity Reform Agreement)
Germany; 2000 Renewable Energy Sources Act (Erneuerbare-Energien-Gesetz EEG)
Great Britain. 2002 Renewables Obligation (RO)
The island of Ireland; 2006 REFIT
Spain; 2004 Special Regime for the production of electricity from RES (Royal Decree 436/2004)
Hokkaido (Japan); 2003 Green Power: Renewable Portfolio Standards (RPS)
*Alberta does not have a major renewable energy incentive scheme, so the establishment of the spot market was chosen as the start
year
Response to the current year integration measures was generally good and on the whole complete. The
response to questions on the start year was less so – respondents reported that often the changes were
not documented and conditions changed quickly so it was difficult to complete the questionnaire. We have
used responses in the measures timeline section of the questionnaire and publically available information
to fill in the missing data where possible.
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2.2.3 Measures timeline
The measures timeline section asked the respondents to identify specific changes that had been
implemented that influence the integration of VRE. Requested information included the details of the
measure, associated costs and benefits of implementation. Response on this section was varied and
where possible, publically available information has been used to supplement the information provided.
2.3 Interviews
We conducted face to face and telephone interviews with several key members of system operators and
policy makers. The interviews were structured around the challenges and measures. Respondents were
able to provide non-documented information that is captured in the case studies.
2.4 Summary of responses and interviews
Table 2.2 summarise the responses to the questionnaire and interviews from the case study jurisdictions.
Table 2.2: Summary of responses to questionnaires and completion of interviews
Jurisdiction Questionnaire Interview
Alberta (Canada);
California (USA); * X
Texas (ERCOT, USA);
Ontario (Canada);
Denmark; **
Germany;
Great Britain. **
The island of Ireland; **
Spain; X
Hokkaido (Japan);
(not requested)
*California did not respond to the challenges section of the questionnaire – for this reason, we have not included a detailed case
study for CAISO **Interviews in Denmark, Ireland and Great Britain involved face to face meetings
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2.5 The Frame-conditions
In order to analyse the development of integration policies in different countries and assess how the
context of a jurisdiction influences the choice of measures, we have categorised the measures into eight
‘frame-conditions’ which describe the set of integration measures. These are:
Dispatch sophistication and maturity,
VRE incentives and dispatch,
Use of Forecasting (UoF),
System services market,
Grid representation,
Interconnector management,
Regulator incentives on the SO, and
Grid code.
Each of the frame-conditions are explained in detail in Chapter 6. We based the categorisation on the
literature, the survey responses and the interviews. They are an attempt to encompass all the types of
integration measure. However, this analysis has been focused on market based jurisdictions, and we have
found it is not appropriate to apply the same analysis to vertically integrated monopoly utilities.
2.6 Installed capacity figures
For the installed capacity of VRE and conventional power stations in the respective jurisdictions we have
used the most recent data available from either government ministries or system operators. It is not always
stated in the sources whether the capacities are gross or net or if they are de-rated. The use of these
figures is to be broad indicators and so whether gross or net is not a large concern. We have assumed that
they have not been de-rated, as this is the usual practice.
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Variable Renewable Energy technologies have a number of specific attributes that differentiate them from
conventional generation. The challenges posed by VRE’s properties must be addressed by both policy
makers and system operators. This section of the report outlines the key properties of VRE and explains
the challenges for policy makers.
3.1 Properties of Variable Renewable Energy
VRE technologies are fundamentally different to conventional generation technologies. Generation from
VRE is:
Variable
Uncertain
Asynchronous
Location specific
Modular
Zero fuel cost
Variable – Power systems work by continuously matching the amount of energy flowing in from generators,
and the amount of energy flowing out to end users. The science and art of generation dispatch has been
refined over the past century to allow controllable generation to match demand as it varies from second to
second (“system balancing”). Many renewable sources are variable in output, and if deployed in large
quantities result in system balancing having to been done by using the remaining connected controllable
generation, or by managing power supplied to energy consumers, or by other means such as the use of
storage.
Figure 3.1: Danish wind and net load variability
Source: Energinet.DK and Mott MacDonald
-1,500
-1,000
-500
0
500
1,000
1,500
2,000
2,500
3,000
3,500
Cap
acit
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W)
Wind production Load (consumption) Net load (Load - wind production)
1 -7 January 2014
3 Challenges for Policy Makers
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Key message: Both load and wind production are variable, but the power system must be able to deal with
the variability of the resulting net load (load minus wind). In the Danish case, wind’s variability is an issue
because net load is more variable than load.
Uncertain – Output from VRE power plants is dependent on natural cycles and weather so is uncertain. A
system operator needs to make sure there is sufficient flexibility in the power system to respond to the
unpredictable output of VRE (while forecasting techniques continue to improve).
Non-synchronous – All modern power systems operate using an Alternating Current (AC). This means that
the turbines of the conventional generators are synchronized i.e. they spin at the same frequency together.
Wind turbines and solar PV do not provide synchronous generation – power electronics is used to
synchronise VRE generation with the system. This does not provide a full substitute for true
synchronisation, as it does not offer millisecond dynamic response, and has potentially major impacts on
the ability of such generation to help the system recover from faults, and in the management of voltage.
Location specific – VRE generation has to be located at the point of resource, opposed to conventional
generation for which the fuel can be delivered to the power station.
Modular – VRE generation technology (especially solar PV) is usually much smaller in scale than
conventional generators.
Zero fuel cost – VRE generators have no fuel costs and so once they are built they can generate electricity
at very low marginal cost.
3.2 Challenges for policy makers
In order to successfully integrate high levels of VRE, policy makers must work to address four key
challenges:
1. Ensuring VRE is deployed in way that reduces its negative system impacts.
2. Introducing market arrangements and operational practices which make the most of the current
installed flexibility, including generation, storage and demand side response.
3. Creating an incentive environment that encourages investment in the required amount of flexibility.
4. Making the most of scarce grid resources.
Ensuring VRE is deployed in way that reduces its negative system impacts
As we have seen, VRE technology is fundamentally different to conventional generation and so the
introduction of VRE on the grid will have some impact. However, these impacts can be reduced by creating
the right regulatory and market environments. In many jurisdictions, grid codes detail specific operational
requirements – effectively reducing the negative system impacts (AEMO 2011). These requirements can
come at a small installation and operational cost for large system wide benefit, especially at high levels of
VRE penetration; however there is continuing debate between SOs and the VRE industry as to the level of
requirements VRE should have to meet.
In addition to grid codes, incentive schemes (such as Feed in Tariffs and Premiums) influence the portfolio
(mix of wind and solar) and geographical development of capacity (Hiroux 2009, IEA 2014).
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This portfolio and geographic spread influences the system impacts, and so incentive schemes can be
designed to mitigate impacts and make the most of the generation.
Market arrangements for handling imbalance risks (the difference between contracted volumes and output
volumes) will also influence the extent to which VRE generators will seek to manage these risks
themselves and so reduce impacts on the wider system.
Introducing market arrangements and operational practices which make the most of the current installed
flexibility, including generation, storage and demand side response
Conventional power plants (Lew 2013), storage facilities (AESO 2014) and demand response (Holttinen
2013) provide the power system with flexibility to deal with VRE (Mueller 2013, Yasuda 2013). However,
market arrangements and operational practices define how these sources of flexibility are used. Less
sophisticated markets may not get the most out of the installed (internal) flexibility – market reforms and
smart operational practices should be able to unlock this potential.
Creating an incentive environment that encourages investment in the required amount of flexibility
For many jurisdictions, market and operational reforms will only go so far to make the most of current
flexible resource, and investment in new flexibility may be needed. The challenge for policy makers is to
create an appropriate incentive structure to encourage investment in the required level of flexibility at an
affordable cost (RAP 2012, Woodhouse 2014).
Making the most of scarce grid resources
Interconnection is a major tool in addressing the integration challenges, but poorly designed operational
and market arrangements can hamper interconnectors ability to provide access to flexibility. Policy makers
face the challenge of reforming arrangements to make the most of interconnector capacity. Similar issues
apply for internal grid capacity, where inappropriate arrangements can unnecessarily constrain access to
internal flexible resources and restrict VRE output.
3.3 Linking policy challenges with integration measures
For each of the above challenges for policy makers there is a suite of potential integration measures that
can be deployed to address them. Each of these measures are explained in more detailed in Chapter 6.
Table 3.1 on the next page provides one plausible categorisation.
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Table 3.1: Integration measures to address each challenge for policymakers
Frame condition category
Measure
Mitigating negative system impacts of VRE
Exploiting existing flexibility
investment incentives for new flexibility
De-bottlenecking the grid
Dispatch sophistication and market maturity
Shorten programme unit times
Shorten gate closure, dispatch times and programme time units
Demand participating in spot market
Storage participating in spot market
Increase price caps
Allow negative pricing
Grid code
Ramp rate limits
High wind ride through
Reactive power support
Frequency response support
Fault-ride through
Emulated inertia
Grid representation
Market splitting
Zonal market (if VRE
exposed to prices)
Introduce LMP (if VRE
exposed to prices)
Incentives on VRE
Increase exposure to energy market
Increase exposure to imbalance risk
Reduce compensation for curtailment
Require VRE to dispatch in energy market
Explicitly incentivise geographical distribution of VRE
Designate renewable zones
Interconnector management
Integrate interconnectors into DAM
Integrate interconnectors into intra-day market
Use interconnectors for balancing
Full market coupling
Regulator incentives
Introduce explicit cost reduction targets for the SO
System services market
Demand as emergency response
Storage as emergency response
$
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Frame condition category
Measure
Mitigating negative system impacts of VRE
Exploiting existing flexibility
investment incentives for new flexibility
De-bottlenecking the grid
Demand participating in Ancillary services
Storage participating in Ancillary services
Encourage VRE participation in regulating/ balancing services
Increase sophistication of system services market
Introduce capacity market
Use of forecasting
Centralised forecasting
Introducing the use of forecasting into calculations for AS requirements
Use of ramping forecasts
Real-time monitoring
Source: Mott MacDonald
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The context of a jurisdiction defines the challenges and constrains the applicability of integration measures.
In this section, we highlight the characteristics of jurisdictions that influence VRE integration.
The characteristics of a jurisdiction that influence the integration challenge are:
The amount and portfolio of VRE.
Geographical distribution of VRE.
The extent and nature of interconnection with other systems: whether the power system is
synchronously connected with another system or is synchronously independent.
The amount of flexible resource available in the jurisdiction2 (and neighbouring power systems if there
is adequate interconnection).
Additionally, the regulatory arrangements of a jurisdiction – whether it is market based, has an independent
system operator, has a vertically integrated monopoly utility – will influence the types of measures that are
available to policy makers. In this study, we have focused on market based jurisdictions and so the
measures relate largely to this type. However, some measures will be appropriate for all jurisdictions.
4.1.1 Amount, portfolio and geographical distribution of VRE on system
The amount of VRE deployed impacts upon the demand for flexibility in the power system. This represents
the scale of the challenge to integrate. Different portfolios, geographic spread and technical aspects of the
deployed VRE can affect the integration challenge.
Important factors are:
Quantity of VRE – at high penetrations, the more VRE deployed the greater the demand for flexibility
(assuming all other variables remain constant).
Geographical spread – can act to smooth out the natural variability of VRE (particularly wind, and solar
to a lesser extent). Aggregating wind generation in Germany has had the effect of reducing the
variability of generation (Stein 2011) – See Figure 4.1.
2 The size of the power system is important in this respect as there are economies of scale that can be gained in terms of the relative amount of reserve capacity required should decrease as the power system grows.
4 Characteristics that influence integration
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Figure 4.1: Smoothing by aggregating: Wind in Germany
Source: Stein 2011
Key message: Aggregating VRE over a large geographical area reduces variability. The first chart is the
output of a single turbine and shows the highest variability. The next two charts shows aggregation over
increasing geographical area and reducing variability.
Correlation of the VRE portfolio output and load – how well the output from the VRE generation
portfolio matches the load profile of the system (on an hourly and seasonal basis) (IEA 2014). Peak
generation of PV occurs during peak electricity demand for electricity in the Western Electricity
Coordinating Council (WECC) due to the use of air conditioning. In this case, PV acts to reduce the net
demand on the power grid (Denholm 2008) – see Figure 4.2. Changing the alignment of PV panels can
increase this benefit by optimising generation for specific times of the day (Hoke & Komor 2012).
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Figure 4.2: PV generation and load in Western Electricity Coordinating Council (WECC)
Source: Denholm 2008
Key message: The figure shows PV generation (in coloured lines) coinciding with peak demand in the
summer months in WECC. This reduces the peak net load for this system. This would not be the case in
jurisdictions where the demand is not driven by air-conditioning.
Mix of wind and solar – VRE technologies have different qualities (wind turbines have a rotating mass,
whereas PV does not, and wind typically has a higher load factor and individual units are often larger in
scale), are often located at different sites, installed at different scales and generate at different times.
There is a wide range in the amount of VRE penetration3 in the case study regions (see Figure 4.3),
ranging from 7 percent (Ontario) to 90 percent (Germany). Most of the installed VRE capacity is wind, and
in only two countries solar penetration is above 10 percent (Germany – 47 percent and Spain – 17
percent).
3 Defined here as installed capacity as a percentage of peak demand
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Figure 4.3: VRE penetration – capacity as a percent of peak demand (2013/14)
Source: Mott MacDonald and other sources
For the purpose of being able to draw out conclusions on types of jurisdictions we have identified four
groups of jurisdictions by the amount of VRE penetration; a low penetration group (less than or equal to 10
percent – Alberta and Ontario), a mid-penetration group (10< VRE penetration <20 – GB, ERCOT,
Hokkaido and California), a high wind only penetration group (>30 percent – Denmark and Ireland) and a
high wind a solar group (Germany and Spain).
4.1.2 Extent and nature of interconnection
Increased interconnection provides flexibility in two ways: by providing access to external sources of
flexibility, or by increasing the geographical size of the balancing area (NERC 2010 IEA 2011, IEA 2014).
Additionally, synchronous connections with other jurisdictions allow for sharing inertia, whereas
synchronously independent jurisdictions must supply their own inertia.
AC (synchronous) interconnection provides all the above benefits, whilst DC (non-synchronous)
interconnection provides only access to external sources of flexibility. It can also improve robustness of
power systems by decoupling them synchronously, which is potentially important if there are concerns over
reliability of one of the systems, or perceived risks of cascade failure.
Interconnection allows connected jurisdictions to share resources. This can mean sharing flexible capacity
when it is required or aggregating VRE resource to reduce variability. In the case study regions, there is a
significant range of the level of interconnection4 (see Figure 4.4), the lowest is ERCOT (1.6 percent) and
the highest in Denmark (96 percent). In fact, Denmark is an outlier as it has more than twice the level of
interconnection as compared to the next closest jurisdiction.
4 Level of interconnection defined here as interconnection capacity as a percentage of peak demand
0%
10%
20%
30%
40%
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De
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Four of the jurisdictions (Ireland, Hokkaido, GB and ERCOT) are synchronously independent jurisdictions.
This means that they can trade energy, but they cannot share inertia5 with other jurisdictions. This is
significant because installed VRE reduces the amount of inertia on a system, so a synchronously
independent power system needs to provide adequate inertia within the system.
Figure 4.4: Level and type of interconnection
*Denmark has two synchronously independent systems; West and East. West Denmark is synchronously connected to continental Europe, and East
Denmark is synchronously connected to the Nordpool system (which includes Norway, Sweden and Finland)
Source: Mott MacDonald and respective system operators
We can identify three categories of jurisdiction based on the type and level of interconnection. A
synchronously independent system group (ERCOT, GB, Hokkaido and Ireland) a weak synchronously
interconnected group (Spain and Alberta) and a strong synchronously connected group (Germany,
Ontario, Denmark and California).
4.1.3 Access to flexible resource
Flexibility is required in any power system, but becomes particularly important when there are increasing
amounts of VRE generation on the power system (NERC 2010). There are three sources of flexibility, (plus
internal and external grid infrastructure), which provides access to flexibility:
1. dispatchable generation;
2. storage;
3. demand side response.
5 Inertia is necessary to keep the power system stable and reduces swings in frequency
0%10%20%30%40%50%60%70%80%90%
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Synchronously independent Synchronously connected
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4.1.3.1 Dispatchable generation
Power plants can supply flexibility by varying their output to account for changes in net load6. There are
three main dimensions to power plant flexibility: Minimum stable generation; ramp rate (speed at which
output can be changed); and lead time (amount of notice required before varying output) (NERC 2010,
Eurelectric 2011, IEA 2011, IEA 2014), Table 4.1 shows typical values of the specific flexibility dimensions
for different technologies.
Hydro reservoir plants are generally considered to be most flexible generating plant – though
meteorological conditions, such as drought and spring thaw, can mean hydro’s flexibility is reduced. Gas
generation is often considered to be the most flexible of thermal plant due to its high ramp rate, which
means it can rapidly respond to changes in net load. This is especially the case for gas engines, but gas
turbine plants are also comparatively flexible, especially the aero-derivative machines. However, many gas
Combined Cycle Gas Turbines (CCGTs) that have been designed for baseload generation have high
minimum stable generation, compared with coal. All GT-based plant also offer less frequency response
capabilities in under-frequency situations than large steam plants7, though this disadvantage can be largely
mitigated through special modifications (either a kind of fuel injection, or augmented mass flow). Nuclear is
typically inflexible as it has a high minimum stable load and low (percentage) ramp rate. Combined Heat
and Power (CHP) plants can provide additional flexibility if combined with thermal storage by heating water
stores during times of low generation and shutting down during times of high VRE generation, using the
VRE generation to provide heat.
Table 4.1: Flexibility of dispatchable generation technologies8
Technology
Minimum stable load
% Ramp rate
(%/min) Lead time, warm (hrs)
Reservoir hydro 5-6*** 15-25 <0.1
Solid biomass ** ** **
Biogas ** ** **
Solar CSP/STE 20-30 4-8 1-4****
Geothermal 10-20 5-6 1-2
Combustion engine bank CC 0 10-100 0.1-0.16
Gas CCGT inflexible 40-50 0.8-6 2-4
Gas CCGT flexible 15-30 6-15 1-2
Gas OCGT 0-30 7-30 0.1-1
Steam turbine (Gas/Oil) 10-50 0.6-7 1-4
Coal inflexible 40-60 0.6-4 5-7
Coal flexible 20-40 4-8 2-5
Lignite 40-60 0.6-6 2-8
Nuclear inflexible 100* 0* na*
Nuclear flexible 40-60* 0.3-5 na*
Source: IEA
Note: the table refer to typical characteristics of existing generation plants. Specific arrangements, especially in new built flexible coal, lignite and nuclear
power plants may increase generation flexibility
6 Net load is the difference between demand and VRE generation which has to be met through conventional generation
7 The natural response of a GT during a falling frequency event is for output to fall, the opposite to a steam generator
8 Technologies can also be of different scales
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* Security regulations may prohibit nuclear from changing output. Reported start-up times are 2 hours from hot state to 2 days;
** Solid biomass and biogas can be combusted in plants that have the characteristics of coal and gas plants;
*** Environmental and other constraints can have a significant impact on the availability of this flexibility;
**** if thermal storage is not fully available, load time can be considerably higher.
Key message: Generator flexibility is determined by a combination of three main factors: minimum stable
load, ramp rates and lead times.
4.1.3.2 Storage
Storage is able to provide flexibility by storing energy when supply exceeds demand and re-generating
electricity when supply is scarce. Storage can also provide other system support services such as
automatic reserve and reactive power. Current storage capacity in Europe is around 5% of total capacity
(DG ENER 2012), of which hydro pumped storage (PS) provides almost 99%, with 99% also being the
figure for the wider world (IEA 2014). While PS is the main established electricity storage option which is
currently viable at utility scale there are many alternative options which are under development, some of
which could be deployed at scale over the next decade. Figure 4.5 shows the discharge time and device
sizes of different storage technologies.
Figure 4.5: Storage technologies
Source: ARUP 2012
Key message: Different storage technologies have a range of capabilities, discharge rates and scales.
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4.1.3.3 Demand side response (DSR)
DSR is the use of demand in either load shifting (moving demand to different times of the day) or load
shedding (reducing certain loads in order to match supply and demand). DSR can be achieved on a
number of scales. Large consumers can provide flexibility through contracting with TSOs or market
participants. Aggregators, or virtual power plants, can aggregate small scale load (and embedded
generation) to provide flexible demand response (NERC 2010, IEA 2011, IEA 2014, Navigant 2012).
4.1.4 Flexibility in the case study regions
The extent of internal flexibility that jurisdictions have depends on the shape of their portfolio of flexible
resources, and largely on their generation plant mix, since storage and demand side are minor players in
most cases. Figure 4.6 shows that non-VRE generating plant break down for the study jurisdictions varies
considerably as does the ratio of dispatchable capacity to peak demand.
Systems with large amounts of reservoir hydro, gas and coal plant will have greater flexibility than those
with nuclear and coal. Systems that have high ratios of dispatchable capacity to peak demand will also
tend to have greater flexible resource, unless the generation capacity is dominated by inflexible nuclear
and/or coal. Of course, these generalisations should not be applied too mechanistically since plant
characteristics can vary significantly. Even nuclear plant can be made to modulate as has been
demonstrated in France and Germany. Storage is easier to assess at present since this is largely
determined by the amount of pumped storage plant. Demand side response is still harder to assess unless
there are explicit mechanisms for utilising this.
Figure 4.6: Non-VRE capacity as a percentage of peak demand
*Denmark has a large amount of CHP, that have hot water storage. Note: DSR is not shown.
Source: Respective system operators
Key message: Generation flexibility is determined by the plant mix and ratio of dispatchable capacity to
peak demand
0%
20%
40%
60%
80%
100%
120%
140%
160%
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Other Storage Nuclear Coal Hydro Oil Gas
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Given the difficulties in assessing the flexibility of dispatchable plant, disaggregating the jurisdictions by the
flexibility in their dispatchable capacity too much may distort findings. Therefore, we have split the
jurisdictions into three groups – high flexibility (Ireland, Spain and California), medium (GB, Germany and
Denmark, ERCOT and Alberta) and low flexibility (Hokkaido and Ontario).
4.1.5 Characteristics summary
Most of the jurisdictions present unique characteristics when combining the categorisation in the four
dimensions (see Table 4.2). None of the jurisdictions have the same categorisation in all four dimensions.
This makes clustering the jurisdictions into groups with similar contexts difficult. For example, Denmark
and Ireland could be in the same group due to both having high wind. However, their level and type of
interconnection is opposite each other, meaning their approaches to the integration challenge could be
very different.
Therefore, our approach to assessing how the context influences the choice of measures will be to
consider each of the characteristics, rather than to cluster into rigid groups.
Table 4.2: Key characteristics of the case study jurisdictions
country VRE portfolio Geographical
distribution of VRE* Interconnection Flexibility
Alberta
California
ERCOT
(2 percent of peak demand)
Ontario
Denmark
Germany
Great Britain
(8 percent of peak demand)
Ireland
(11 percent of peak demand)
Spain
Hokkaido**
(10 percent of peak demand)
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*Geographical distribution is based on maps of VRE deployment (found in Volume II: Case Studies) and
discussions with system operators. ** Hokkaido is the only jurisdiction in the study which has a vertically
integrated monopoly utility – this will influence the types of integration measures that can be implemented
by policy makers.
Source: Mott MacDonald
High wind and solar
High wind
Mid VRE penetration
Low VRE penetration
Strongly interconnected
Weakly interconnected
Synchronously Independent
High flexibility
Low flexibility
Well distributed
Mostly distributed
High concentration in few areas
Mostly in one area
Mid flexibility
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The properties of VRE create a number of specific challenges that must be addressed by system operators
and policy makers. Whilst this report is written for the benefit of policy makers, here we explain some of the
more technical issue that need to be understood to gain a full appreciation of the integration challenge. We
define these challenges as:
1. Short term active power balancing (inertia and frequency response)
2. Ramping
3. Voltage stability (voltage profile and reactive power)
4. Transient stability
5. Congestion and grid constraints
6. Resource adequacy and long term flexibility investments
5.1.1 Short term active power balancing (inertia and frequency response)
Replacing conventional generation with VRE generation reduces the amount of inertia on the
system, which can lead to stability issues
Power system stability is dependent on controlling the system frequency (usually at around 50 Hz or 60
Hz), and the Rate of Change of Frequency (RoCoF), within strict limits by continuously matching supply
and demand (O’Sullivan 2010). If frequency is not contained, generation and/or demand may trip to protect
the equipment from damaging the system environment.
Conventional generators operate in synchronism with the grid frequency that is controlled by the
contribution of all connected conventional generators. The turbines and the electrical alternators are able
to store kinetic energy, through the mechanical inertia of the rotating masses. The kinetic energy may
either be released instantaneously when incidents, such as loss of one or more generators, cause a
system frequency drop or be accumulated instantaneously when incidents, such as loss of demand, cause
a system frequency rise. A power system with high inertia is more stable than one with low inertia because
the latter experiences faster frequency variations which are more challenging to control.
Non-synchronous generators (wind and solar PV) are generally unable to provide significant inertial
response to incidents that cause system frequency variation because they interface with the network via
power electronic converters. The converter practically decouples the non-synchronous wind generators’
mechanical conversion system and controls electronically the output9. Replacing conventional generation
with VRE generation reduces the amount of inertia on the system, which can lead to stability issues.
Example of Ireland: The Island of Ireland has a synchronously independent power system (its two
interconnectors with Great Britain are DC links) operated by the System Operator, EirGrid. Installed wind
capacity has reached 52 percent of peak demand. Having a large amount of asynchronous generation on
the system at any one time poses concern for the stability of the system, and so EirGrid has conducted
numerous studies into (among other things) the stability limits of instantaneous wind penetration due to
inertia concerns. As a result of extensive system modelling,
9 Synthetic inertia can be achieved through power electronic controllers which provide a similar response though the reaction may not be as quick as natural inertia. However, this is an emerging technology and very few turbines have this kind of capability.
5 Challenges for system operators
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EirGrid imposes an operating limit for System Non Synchronous Penetration (SNSP) – equal to wind
generation plus DC imports divided by demand plus DC exports – of 50 percent. In the event that wind
generation can generate more, it is curtailed, though they are implementing changes that would allow the
SNSP to reach 75 percent.
5.1.2 Ramping
Increased VRE may lead to an increased need for ramping capability for the rest of the power
system.
Ramping is the requirement of the system to meet rapid swings in the supply demand balance to meet
system load. Increasing amounts of solar and wind has led to changing ramping requirements on some
systems. Systems with high PV contributions are likely to face more rapid ramps in the early evening as
solar output falls and demand rises (the so-called “duck curve” in California – see Figure 5.1).
Figure 5.1: The “Duck Curve” – increased ramping requirements in California
Source: CAISO
Key message: Increasing VRE penetration may lead to increased ramping requirements, as in the case of
solar generation in California.
These increased ramp rates mean that the SO has to ensure that it has sufficient dispatchable plant and
interconnector capacity (or demand side response) on line to respond, while at the same time covering its
operating reserve requirement during these period.
This can create a further challenge in that much of the existing fleet of dispatchable plant may not have
been designed for this type of duty, so for example coal or gas fired plant designed for baseload service
may now be expected to run on a variable duty cycle. This may require significant re-engineering (beyond
monitoring, training and component adaptation) to be done, and will tend to increase operating cost and
reduce thermal efficiency (hence increasing carbon emissions per MWh generated).
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5.1.3 Voltage stability
Replacing conventional generation with VRE generation raises challenging voltage control issues
particularly in networks with large concentrations of VRE generation located remotely from load
centres or in networks with distributed VRE generation.
In an AC power system the transfer of real power between generators and loads is underpinned by
maintaining an adequate voltage profile across the transmission and the distribution network. In order to
maintain the voltage profile an amount of non-energy carrying current will be transmitted between points in
the network in the form of reactive power. In an air mattress analogy the reactive power represents the
additional air that has to be pumped into a mattress that loses air through imperfections in the material so
that the firmness of the mattress is maintained intact in all its points. The larger/longer the mattress the
more supplementary air has to be pumped.
Unlike frequency control which is effected system wide, the control of reactive power is done at a local and
on a regional basis influencing the voltage profile across the network. Conventional generators and a
number of devices have the ability of controlling their reactive power output within the range of their
physical characteristics. Legacy wind conversion systems have limited reactive power control range
however the new generation using fully-converted systems are able to deliver reactive power output right
up to the design rating envelope. The networks where legacy wind conversion system are predominantly
deployed experience numerous challenges on controlling the voltage profile due to these wind system’s
weak contribution to reactive power exchange and the inherent characteristics of the network lacking other
means of control due to the predominant presence of fixed tap controls on the transformers. Even fully
converted wind turbine generators usually have a reactive capability short of that of the conventional
synchronous generators that are being displaced. These challenges are particularly exacerbated during
high VRE production periods because there is less synchronous generation on the system.
Some solutions to reactive power management can lie with generators (changing the characteristics of
their equipment, if prompted by a grid code), and others with network companies (equipping transformers
with on-load tap changers to allow better management of voltage, installing “FACTS” devices to manage
reactive power problems). Most network companies are familiar with these issues, but the deployment of
large amounts of VRE can change the location and scale of actions required.
5.1.4 Transient stability
The effect of replacing conventional generation with VRE generation may lead to the power system
becoming more susceptible to transient disturbances10.
Transient stability is the ability of a synchronous power system to maintain synchronisation of its connected
units when subjected to a severe transient disturbance such as a fault on transmission facilities (or
generator trip) (O’Sullivan 2010). During the instance of the fault (typically a few tens of milliseconds), the
connected conventional generators tend to accelerate because little actual load is demanded by the
network experiencing the fault that depresses the voltage profile. When the fault is cleared, all the
connected generators will be slightly out of synchronism with each other depending on their inertias and
electrical distance from the fault.
10 Some studies suggest that VRE generators will increase the transient stability of a system. However, evidence from EirGrid (for example, see the “All Island TSO Facilitation of Renewables Studies”, 2010) suggest that at high levels of VRE penetration, transient stability of a system will decrease.
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The stability of the system post fault clearance depends on the electromechanical characteristics of the
power plant and power network components and is studied as part of power system design. Generators on
the ends of long transmission lines tend to be more vulnerable. The large scale deployment of non-
synchronous plant could change the design basis of the system and needs to be based on appropriate
analysis. Many transient stability problems can in practice be handled through appropriate control and
protection strategies.
5.1.5 Congestion and grid constraints
Congestion problems may arise where the level of deployment of VRE has exceeded the capacity
of transmission and distribution system to handle the load-flows.
Congestion is more likely in jurisdictions which apply a ‘connect and manage’ approach to bringing on
renewables and in jurisdictions which have geographical concentrations of VRE resources located at some
distance from load centre. The constrained transmission capacity between load centres and concentrated
VRE resources usually require curtailment of the VRE resource output. Occasionally in densely meshed
transmission system with multiple loops that are located in several jurisdictions across borders, the AC
power flows naturally choosing the least resistance paths may cause congestion within an external
jurisdiction and raise significant challenges for the power flow control within the transiting jurisdiction.
Texas, Great Britain and Germany all provide examples of jurisdictions in which congestion is an issue
(See respective case studies in Volume II of this report). This can be seen as due to their common
characteristic of developing most of the wind generation in a specific location, usually far from the load
centres. Each of the three jurisdictions have taken different approaches to the problem – Texas has
implemented Competitive Renewable Energy Zones (CREZ) and Locational Marginal Pricing (LMP),
National Grid in Great Britain is building the ‘Bootstraps’ (undersea HVDC to bring wind from Scotland to
England) and Germany has implemented a Grid Expansion law to prioritise north to south transmission
and reduce planning times.
5.1.6 Resource adequacy and long term flexibility investments
VRE generation can put at risk a power systems ability to meet peak demand by causing
conventional generation to be uneconomic.
Resource adequacy (often called generation or supply adequacy) is the ability of the power system to
provide sufficient capacity to meet demand. VRE generators contribute considerably less to resource
adequacy (Dent 2010, IEA 2013), on a MW for MWh basis, than conventional generators due to their
inherent uncertainty and variability (Lannoye 2012).
Additionally, the increase of VRE in a power system can have significant effects on the business models of
conventional generators. VRE generation can dampen wholesale electricity prices and push conventional
generation out of the merit order because of their low short run marginal cost (Clifford and Clancy 2011,
SensfuB 2011). Conventional generators lose potential revenue, which can make their continued
operation, or new deployment, financially uneconomic. This tends to happen more to power stations that
are designed for greater flexibility, rather than baseload, as they are traditionally the marginal plant and are
pushed out of the merit order due to the increase of VRE. The process of plant retirements and additions
needs to be managed, either directly or using appropriate pricing signals. This has been an issue
especially in GB and Germany, where low spark spreads in forward and day ahead markets have hit the
profitability and running hours for legacy gas plant which has led to capacity being taken out of service.
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The low spark spreads are also deterring new investment in firm and flexible gas plant which is widely
seen as being required to replace projected closures of coal (and in Germany, nuclear) plant. Power
station retirements will be necessary for a power system transformation to take place, though resource
adequacy needs to be secured during and after this transformation.
5.2 Challenges in the case study regions
As part of the survey, we asked system operators to rate their perception of the severity of each of the six
discrete challenges on a scale of 1 to 5, with 5 being the most severe11. Nine jurisdictions responded to the
question (see Table 5.1).
Table 5.1: Perception of the severity of challenges
Inertia Reactive
power Transient
stability Congestion Ramping Supply
adequacy
Alberta 2 5 2 2 4 2
ERCOT*** 3 3 3 4 5 5
Ontario* 1 1 1 3 3 3
Denmark 3 5 3 1 4 2
Germany 1 5 1 5 5 5
GB 5 3 3 4 4 4
Ireland** 4 2 1 3 2 2
Spain 2 4 3 2 5 5
Hokkaido 3 5 4 5 5 5
*Respondent from Ontario did not rate the challenges by number, but described Inertia, reactive power and transient stability as not
an issue currently, and congestion, ramping and supply adequacy as an issue, but not severe.
** Respondent from EirGrid gave ratings for the current year (2014), and expectations of the future (2018 and 2022) – the above for
Ireland is for 2014.
*** Respondents from ERCOT gave inertia a ‘2’’, but qualified this saying that inertia will become more of an issue in the future.
Source: Mott MacDonald
In general, ramping and supply adequacy are seen as the major challenges. Ramping is even perceived to
be a major challenge in Alberta, which has a low penetration of VRE. Ramping and supply adequacy
appear to be a concern regardless of the characteristics of a jurisdiction.
Inertia is seen as a major issue in both GB and Ireland, and although ERCOT report mid-level concern,
they report that it will be a concern in the future (the difference in scoring between GB and ERCOT is partly
due to a difference in timeframe considered – GB was mainly referring to the future, while ERCCOT was
referring to the present). These are synchronously independent systems and so will have to supply their
own inertia. Inertia is seen as a low level concern in Germany, Spain and Denmark, the three countries
with the highest penetration of VRE. If a jurisdiction is synchronously connected to its neighbours,
provision of inertia should not be as much of a challenge for integrating high levels of VRE, provided that
inertia can be accessed in neighbouring jurisdictions.
11 The question posed was not specific to a timeframe.
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Reactive power is perceived to be a major challenge in Germany, Denmark and Spain – the three
countries with the highest VRE penetration and Germany and Denmark have high levels of
interconnection.
Transient stability is seen as a low to mid challenge in all jurisdictions and there appears to be no link to
the characteristics of a jurisdiction.
Congestion is mostly an issue in jurisdictions with poor geographical distribution of VRE (Germany,
ERCOT and GB). ERCOT and GB have mid-level VRE penetration and low interconnection, suggesting
congestion concerns can manifest themselves in jurisdictions that lack adequate interconnection before
they achieve high levels of penetration.
5.3 Challenges on the distribution system
Embedded solar and other renewable generation connections (such as roof top solar in home and offices)
are becoming more common and visible in through many European and North America jurisdictions. A lot
of these connections are at low voltage (230V and 210V single phase in Europe and North America) and
are connected to existing developments.
While this generation has a number of advantages – requiring no or limited dedicated land area, using
existing infrastructure for the connection and has low social impacts – it is creating issues for the electrical
distribution network to which it connects.
The majority of these issues are related to the fact that electrical distribution networks have been designed
only for electricity to flow in one direction - from the network to the load. Embedded solar generation can
disrupt this causing the load (homes) to start generating and exporting to the network. This is termed a
reverse power flow. Reverse power flows are problematic for a number of reasons:
1. In a network the voltage must be maintained within limits (In most of Europe up to +/-10%). Power
flows from a high voltage to a low voltage e.g. from 240V at the grid substation to 220V at the
customers house for example. The voltage at the grid substation is determined by the design of the
transformer, normally for transformers connected to LV these would be fixed for a high LV voltage
(e.g. 240V+). If a group of customers stops absorbing power from the network and starts exporting
power the voltage at the point of the generation will rise to above that of the grid substation. If this
voltage rises higher than the rated voltage of the equipment this may cause electrical insulation to
fail. This issue may resolved by using a variable voltage transformer (one with a device fitted called a
tap changer). While this is common practice at higher voltages and is not technically complex but
would require a widespread replacement of LV transformers which would be costly.
2. In most LV distribution networks the system is split into three wires/phases (red, yellow, blue), each of
these phases is used to supply a small load group (a small street or business). The loads on each of
phases must be approximately equal as any mismatch in loading will flow via the neutral wire. If one
load group (for instance, a south facing street with lots of solar) has a great deal of generation this will
cause phase imbalance potentially overloading the neutral connection causing it to fail. This issue
can be overcome by connecting all three phase to the load with generation, which of course would
have cost implications.
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3. Distribution networks are protected by systems including circuit breakers and/or fuses which are
designed to isolate faults in what is generally called “protection”. However, some of the fault locating
technology in these systems is built on the assumption of flow in one direction. If the flow is not in this
direction then the circuit breakers may take longer to isolate a faulted item of equipment or may
isolate more of the network than required. Again, this problem can be overcome by redesigning the
protection schemes.
It is worth noting that the solutions to all these issues are not complex but all require replacement or
refurbishment of “last mile” infrastructure and as such may be expensive.
If no action is taken to modify the distribution network for reverse power flows, it is possible that the
networks will survive without common failures. Most LV systems will cope with higher voltages than their
rated capacities and the neutral wires are normally the same as the phase wires so the likelihood of failure
is low. Also since high LV voltage and neutral loading are generally unmonitored the problem may go
undetected until the network becomes seriously stressed and a catastrophic failure occurs.
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In this report, we define measures for integrating VRE as specific actions that policy makers and system
operators can take to address the integration challenges. We have identified from the literature eight
specific categories (‘frame-conditions’) of measures (see Figure 6.1). The frame-conditions cover market
rules and operational practices.
Figure 6.1: The eight frame conditions
Source: Mott MacDonald
The purpose of identifying the eight categories of measures above is to enable us to draw conclusions
about the types of measures implemented across a diverse range of jurisdictions.
Our framework for understanding the types of policies and conditions for integration has been developed
with a focus on market based powers system as opposed to vertically integrated monopoly utilities
because of the case studies selected (Hokkaido is the only jurisdiction in the study with a vertically
integrated monopoly utility). This poses difficulty in assessing and comparing integration policies,
particularly on the side of investing in new flexibility. In some ways, vertically integrated monopoly utilities
may have a more straightforward route to the implementation of new processes for integration partly
because they have access to information across all sectors.
6.1 Dispatch sophistication and market maturity
This refers to the arrangements for dispatching non-VRE generation in the jurisdiction. Non-VRE
generation is important because the flexibility offered by these generators can help to deal with the
variability of VRE. Included in dispatch sophistication and market maturity is:
Gate closure – the length of time before operation in which the market closes. Shorter gate closures
allow participants to take more accurate forecasts into account.
Programme time units – electricity is traded in time blocks, but variation in VRE generation and
demand is continuous. Allowing trading of shorter time blocks should represent these variations to a
greater degree.
Electricity price caps – many jurisdictions have price caps on electricity. In a high VRE power system,
flexible plant could base their business model on generating just a few times in the year if there is an
adequate scarcity pricing incentive. Price caps could have the effect of reducing this incentive.
Negative pricing – allows bids of below zero price, providing disincentives to generate and incentives
for both storage and demand sider response.
There are a wide range of approaches to dispatch in the case study jurisdictions (see Table 6.1). Gate
closure times range from 5 minutes to 6 hours, and programme units range from 5 minutes to an hour. It
should be noted that dispatch sophistication and market maturity do not necessarily run in parallel.
Dispatch sophistication
System services market
Grid representation
Use of forecasting
Interconnector management
Grid codeVRE incentives and dispatch
$Regulator incentives on SO
6 Measures for integrating VRE
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It is quite possible for a jurisdiction to have an undeveloped market in the sense of having a low level of
intra-day trading with a gate closure many hours ahead of the trading period, while at the same time having
an extremely sophisticated dispatch arrangement, whereby the SO can re-dispatch as required up to and
through the trading period. Ireland probably falls in this category. It is even conceivable that an SO within a
traditional vertically integrated system could also apply a sophisticated dispatch mechanism, although
there are no obvious candidates.
There is also a range of electricity price caps effective in the markets – from $1,000/MWh to un-capped.
There has been a trend towards increasing price caps (for example in ERCOT and Denmark) in order to
allow for higher levels of scarcity pricing that could incentivise flexible generation. Negative pricing has also
been introduced in most jurisdictions. Jurisdictions that report high concern about resource adequacy –
GB, ERCOT and Germany – all either have high price caps12 or no price caps at all, whereas the
remainder have lower caps (apart from California). Scarcity pricing (very high prices for a short amount of
time) can be used to encourage new investment and requires high or non-existent price caps.
Table 6.1: Price caps and negative pricing
Gate closure Programme units/trading blocks Price caps
Negative pricing
Alberta [pending] [pending] $1,000/MWh x
California 75 minutes (5 minute dispatch)
15 minute (unit commitment)
Uncapped
ERCOT 1 hour (5 minute dispatch)
5 minutes* $7,500/MWh*
Ontario 2 hours 1 hour $2,000/MWh
Denmark 1 hour 1 hour €3,000/MWh
Germany 15 minutes 15 minutes €3,000/MWh day ahead,
€9999/MWh on intraday
GB 1 hour 30 minutes Uncapped
Ireland 6 hours 1 hour €1,000/MWh
Spain 40 minutes 1 hour €180/MWh x
Hokkaido 4 hours** 30 minutes n/a n/a
*ERCOT’s price cap is currently at $5,000/MWh, which will increase to $7,500 in summer 2014 and to $9,000/MWh in summer 2015
**In Japan, the Electric Power Companies (EPCOs) are vertically integrated, meaning there is not a competitive generation market
Source: Respective System Operators and Mott MacDonald
12 In theory, price caps should be set at the Value of Lost Load (approx. $10,000/MWh or more) to allow scarcity pricing but to mitigate abuse of market power. In this instance we define high price caps as being close to the value of lost load.
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Reducing dispatch times in ERCOT: In 2010, ERCOT implemented market reforms that included reducing
dispatch times from 15 minutes to 5 minutes. As a result of the reform the amount of regulation reserve
used by ERCOT to manage imbalances decreased significantly (see Figure 6.2). This should result in
system wide cost savings.
Figure 6.2: Regulating reserve requirement in ERCOT
Source: GE Energy
Key message: as a result of reducing the dispatch time from 15 minutes to 5 minutes, ERCOT has been
able to reduce regulating reserve requirement.
6.2 VRE incentives and dispatch
In most jurisdictions, VRE deployment has happened on a significant scale due to renewables
programmes (such as FiT) which provide economic incentives to deploy VRE generation. The design of
these programme influences developers’ decisions, such as the location or design of a wind farm. For
example if a developer’s revenue is based on a fixed price for electricity generated, the developer will seek
sites where the highest wind resource is, regardless of the time of generation. If a programme exposes
VRE generators to time of generation pricing (for example in the spot market), developers may seek to
maximise revenue by developing sites where the wind resource is more positively correlated to demand.
Additionally, market arrangements may: require VRE generators to dispatch (M Ashlstrom 2013), expose
VRE generators to the imbalance risk; and reduce compensation for curtailment (L Bird 2014).
Exposing VRE generators to the market forces developers and generators to consider the value of the
energy generated by involving market exposure in their business models. This should lead to decision
making that reduces the negative system impacts.
1,000
900
800
700
600
500
400
300
08-07 02-08 08-08 02-09 08-09 02-10 08-10 02-11 08-11 02-12
Cap
acit
y (M
W)
Time (date-month)
Avg. Reg. Up requirement Avg. Reg. Down requirement
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However, exposing VRE generators to the market increases risk: a revenue stream that is dependent on
time of generation pricing and receives no compensation in the event of curtailment is riskier than a
revenue stream which has a fixed price for energy generation regardless of curtailment. The added risk
increases the cost because investors will require a higher return on their investment.
The case study jurisdictions take a range of approaches to VRE incentives and dispatch (see Table 6.2).
Table 6.2: VRE incentives and dispatch
Incentive mechanism
Direct incentive for geographical dispersion Dispatch
Imbalance risk exposure
Compensation for curtailment
Alberta None x * None None
California FiT x [information not
available]
Moderate None
ERCOT None** *** Moderate None
Ontario FiT - linked to market x None Partial
Denmark FiT x Full Partial
Germany Premium**** x Full Partial
GB Premium***** x Full Partial
Ireland FiT x x None Partial
Spain None****** x Full Partial
Hokkaido FiT x None Partial
*Alberta is currently piloting dispatch of VRE in the market **ERCOT’s Production Tax Credit (PTC) ended in 2013 for new
development ***ERCOT’s CREZ designates renewable development zones for wind projects ****In Germany, generators can opt for
FiT or premium, currently about two thirds of onshore wind capacity has opted for the premium *****In the UK, there is a transitional
period from 2014 to 2017 in which the Renewables Obligation (RO), a premium mechanism is being replaced by the Contracts for
Difference (CfD), an auction based FiT. ******Spain’s premium scheme has ended
Source: Respective System Operators and Mott MacDonald
The most common incentive mechanism is the FiT, though there is a trend towards increasing market
exposure in this respect. For example, in Germany, VRE generators can now choose the FiT or premium
on market prices and both ERCOT and Spain have cancelled their respective premium incentives for new
generators. There has also been a trend towards requiring wind generators to dispatch in the market and
increasing the imbalance risk exposure generators face.
None of the jurisdictions in the study directly incentivise the geographical dispersion of VRE generators.
There appears to be no contextual influence upon the approach to VRE incentives and dispatch.
VRE incentives in Alberta: Alberta is an interesting case as it has no direct subsidy13 (such as FiT or
Renewable Portfolio Standard (RPS)) for renewable energy (the only indirect benefit to wind is a small
carbon price paid by emitters), and so renewables deployment is on the basis of the revenues that can be
received through the wholesale market.
13 The federal Canadian incentive for wind (1ct/kWh) closed to new wind farms in 2011
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Considering this, Alberta has a significant amount of wind capacity installed already, at about 1,100 MW
(10 percent of peak demand). There is also an estimated 4.03 MW of solar PV on the system, installed on
the basis of net billing.
Alberta is the only jurisdiction that does not provide a direct incentive mechanism for VRE generators, and
wind capacity is currently 10 percent of peak demand. Policy makers in Alberta report that developers are
seeking sites that have a better match with the prevailing load profile, sacrificing load factor to achieve
better prices (see Figure 6.3).
Wind resource in Alberta is strongest in the far south of the province (see Figure 6.3 left side), which has
led to the majority of wind deployment in this area. However, the wind profile north of the high wind region
is more positively correlated with demand14 and so can achieve higher average electricity price (see Figure
6.4). This has led to more recent deployment of wind farms and planned developments in more northerly
regions (see Figure 6.3, right side), since the wind generators are fully exposed to the pool price. This
increasingly disperse portfolio should be less costly to integrate than if the capacity was located in a
confined area.
Figure 6.3: Alberta wind speed distribution Geographical deployment
Source: Environment Canada, Alberta Environment and the US Climate Data Centre (left hand map); Albert Energy and Mott
MacDonald (right hand map)
14 Most of demand (about 80 percent) in Alberta is industrial, so demand peaks in the day and drops in the evening – which is opposite to the wind generation profile in the south of the province
OPERATING
APPROVED
PLANNED
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Key message: while the strongest resource is in the far south, deployment is beginning to spread north,
partly due to the fact that northern farms can capture better average pool prices. Greater geographical
diversity should help to minimise integration challenges and cost.
Figure 6.4: Average pool price captured by northern and southern wind farm
Source: EDC Associates
Key message: northern wind farms (defined by EDC Associates as Ghost Pine, Wintering Hills and Halkirk)
capture a higher average pool price than southern wind farms because the generation portfolio is more
positively correlated with demand. This is contributing to a geographically diversifying wind portfolio.
VRE dispatch in Ontario: From 11 September 2013 wind generators have been required to dispatch in the
electricity market in Ontario. Before this measure was implemented, wind generation was treated as must-
run and could not be dispatched down (curtailed) in normal operation conditions. Ontario has a high
proportion of nuclear and hydro generation and in September, some of the hydro generation was must run
due to the spring thaw (to keep reservoir levels manageable). This created an oversupply issue in the
morning of 10 September 2013 (see Figure 6.5) when nuclear, wind and hydro generation was higher than
demand. The oversupply was dealt with by partially turning down the nuclear plant – which is an expensive
operational intervention to make.
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Figure 6.5: Oversupply in Ontario leading to nuclear shutdown
Source: OIESO
Key message: OIESO’s main challenge is over-supply at low demand periods and inflexible plant.
Since the introduction of wind dispatch, the curtailment of wind (which is a more economic option than
nuclear curtailment) can be utilised, as happened on 25 November 2013 (see Figure 6.6).
Figure 6.6: Dispatch of wind allows for economic wind curtailment in Ontario
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Key message: Requiring VRE to dispatch allows for more economic operation of the power system. In
Ontario’s case, curtailing wind is more economic than nuclear shutdown.
6.3 Use of forecasting
Forecasting of wind and solar generation can give system operators and market participants foresight into
future operating conditions, and forecasting techniques are continuously improving. Forecasting, by its
inherent nature, also improves significantly the closer to real time the forecast is made. An important
element in the potential for forecasting is how the forecasts are used. Forecasts can be used to inform day
ahead scheduling, intra-day and near real time dispatch, system security monitoring and requirements for
system services. A recent forecasting development has been the use of ramping forecasts, which report
the likelihood of large wind ramps within a specified time. The value of forecasting increases with VRE
capacity additions (see Figure 6.7)
Figure 6.7: Annual operating cost savings ($million) due to implementation of state of the art forecasting
Source: Piwko
Key message: Annual operating cost savings due to the implementation of state of the art wind forecasting
at different capacities of wind in ERCOT were estimated by Piwko. These estimates translate to a cost
saving of almost $200 million at current capacity.
We asked system operators how forecasting was used in their jurisdictions (see Table 6.3). Only in
Hokkaido is forecasting of VRE not used. In general, VRE forecasts are used for scheduling and informing
the requirements for system services (reserves or regulating). In ERCOT and Alberta ramping forecasts
have been developed to alert operators to the potential for large wind ramps so that they can take
preventative measures such as limiting ramp rate of wind or scheduling other plant.
0
100
200
300
400
500
600
5 10 15
Esti
mat
ed
co
st s
avin
gs (
$m
)
Wind capacity (GW)
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Table 6.3: Use of forecasting in the case study regions
Use of forecasting of VRE
Alberta Centralised forecast aggregated from 75 individual forecasts. Day ahead forecast used operating reserve requirements and for Wind Power Ramp Management (WPRM) requirements.
California SO has used centralised forecasting since 2004 – used for day ahead scheduling and near real time dispatch (PJM study).
ERCOT Centralised forecasting is used to inform day ahead and hour ahead commitment schedules. Historic wind forecast errors inform the level of Regulation Reserve (part of the ancillary services) required. Also introduced and is developing a Large Ramp Alert System in order to better manage ramp events.
Ontario SO uses centralised forecasting for wind farms greater than 5MW for day ahead scheduling and system monitoring. SO uses 2-7day forecasts for outage planning, 0-48 hour forecasting for day ahead and hourly scheduling, 5-minute forecasting for real-time dispatch and ramp forecasting for situational awareness.
Denmark Long term and short term centralised forecasts inform system planning, scheduling and for proactive regulating power. The TSO is also required to sell some VRE in the market, and uses the forecast to inform.
Germany TSOs procure their own independent day ahead and intraday forecasts. FIT rules require TSOs to purchase VRE energy from (some) generators and sell this into the market, so forecasts are used to inform these positions as well as making security assessments.
GB SO publishes day ahead forecasts which are used to in the calculation for special wind reserve requirements and to assess security and stability conditions. Operators in the control also get wind generation forecast four hours ahead which is used to inform reserve requirements.
Ireland Wind forecasting is used in scheduling power plants.
Spain Forecasting is used in calculation of reserve requirements and in the Renewable Energy Control Centre to monitor and assess the likelihood of system security issues.
Hokkaido Hepco does not use forecasting to any significant degree, though plans to start forecasting in the near future.
Source: Respective System Operators and Mott MacDonald
6.4 Grid code for VRE
Grid codes specify technical requirements for connection to, and use of power generation facilities. Many
jurisdictions include specific requirements for VRE technologies. These requirements may include:
Fault Ride Through (FRT) – which specifies procedures for responding to system faults and
disturbances during which the generators must stay connected. FRT requirements help stabilise the
system in times of disturbance.
Active power and frequency control – which can specify a number of properties such as maximum
power, gradient or ramping constraints, requirements to accept dispatch instructions and others. These
requirements determine how controllable VRE generators are to system operators.
Reactive and voltage control – which can specify requirements for reactive power generation
capabilities. This helps system operators manage reactive power and voltage across the power system
In addition to the above, developments in VRE technologies may allow for future grid codes to include
specific requirements for high wind ride through (where wind generation gradually reduces at high wind
speeds rather than cutting off to protect equipment) and synthetic inertia.
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Note there are different approaches to the extent to which grid code requirements should be imposed on
variable renewable generators. It may be more economical to procure the needed services in a system
service market, rather than requiring all generators to provide the service.
Grid codes requirements for VRE can specify a number of specific technical parameters. Each jurisdiction
specifies its own VRE grid code requirements (see Table 6.4), for example, California specifies FRT and
reactive power requirements for both wind and solar, but no frequency response requirements. In general,
the first specific requirement for VRE is FRT, which determines the conditions under which VRE
generators must stay connected.
No jurisdiction yet specifies requirements for either High Wind Ride Through (allows wind farms to stay
online at very high wind speeds) or synthetic inertia (allows wind farm to provide frequency response close
to that of real inertia), though these requirements are being considered. The characteristics of a jurisdiction
seems to have little bearing on the requirements specified in the grid code, except that Alberta and Ireland
only specify wind requirements, as there is low expectation for much solar to be connected.
Table 6.4: Grid code comparison in case study jurisdictions
FRT Reactive power Frequency response High wind
ride through Synthetic
inertia
Alberta
California
ERCOT
Ontario
Denmark
Pilot
Germany
GB
*
Ireland
Spain
Hokkaido
*Synthetic inertia for wind turbines is currently being considered in GB.
Source: Respective System Operators and Mott MacDonald
Requirements for wind and solar
Requirements for wind only
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6.4.1 Grid code for non-VRE generating plant
Grid code obligations for non-VRE generating plant have also seen a general tightening in standards in
Europe and North America over recent decades. This has reflected the need to control plant characteristics
in a world which has seen a shift away from central utility procurement (where plant were built to a certain
specification) towards independent power producers, building to a minimum functional specification. The
main change has probably been a successive tightening in frequency response requirements for gas
turbine based plant, which in the early years of CCGT deployment were granted derogations versus the
standard for large steam turbine based plant. These changes have been applied incrementally, such that
older vintages of plant have to comply with less onerous standards. A few system operators are now
understood to be considering requiring retroactive application of new standards. For gas turbine plant,
such retrofits would require modifications to burner control systems, which are not so onerous in terms of
capital costs, although there would be increased servicing requirement.
6.5 System services market
System services (or ancillary services) provide stability and security to the power system. They may be
required to assist a system operator in managing frequency, voltage stability, etc. However, the
specification is unique to the exact characteristics of the power system in each jurisdiction. Typically the
frequency management products are termed frequency containment, frequency restoration,, replacement
and high frequency reserve. Frequency containment provides automatic response to large disturbances to
arrest a change in frequency; frequency restoration provides automatic response to variations in frequency
over short time frames (within seconds) to correct a frequency change and replacement is used to respond
to frequency variations over longer time frames (minutes) (Milligan 2010). High frequency response is the
automatic capability to reduce injections into (or increase demand on) the system in the case of large step
increase in frequency arising from the sudden loss of demand (most likely through an interconnector that is
exporting).This is generally provided by automatic cut-out arrangements with large generators. Some
jurisdictions also include other products, such as provision of reactive power capability and delivery and
ramping, in the system services markets. Ramping is the provision of a specified ramp rates (normally for
generation) measured in MW/min (or %/min) and is instructed by the SO. This contrasts with upward and
downward regulation, which is typically an automatic response on a shorter time frame.
Providing frequency reserves can incur a cost to the provider (generator, storage operator or demand) and
so needs to be remunerated or mandated. Creating competitive markets for the provision of the products,
and allowing participation from technologies as long as they meet the technical requirements, should allow
the system operator to procure the services, and hence ensure system stability and security, more
efficiently.
The uncertainty and variability inherent in VRE generation can create additional requirements for system
services to balance supply and demand (see Figure 6.8). Improving the efficiency of procuring system
services will play a role in reducing the total integration costs of VRE.
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Figure 6.8: Use of frequency reserves (system services) in Spain plotted against installed wind power capacity
Source: NREL 2010
Key message: use of frequency reserve increases with installed wind capacity, due to variability in wind
output requiring more use of reserves.
Most jurisdictions have three main products, with market or regulated prices (see Table 6.5).
Table 6.5: System services market
Frequency containment
Frequency restoration Replacement
Reactive power Ramping
Alberta Remuneration Marginal Marginal Grid code x
California [information not available]
[information not available]
Marginal Grid code Remuneration
ERCOT Marginal Marginal Marginal Grid code x*
Ontario Mandatory Remuneration Marginal Grid code x
Denmark Marginal Marginal Marginal Grid code x
Germany Remuneration Remuneration Remuneration Remuneration x
GB Marginal Marginal Marginal Marginal x
Ireland Remuneration Remuneration Remuneration Remuneration x*
Spain Mandatory Marginal Marginal Grid code Yes
Hokkaido** n/a n/a n/a n/a n/a
*In both Ireland and ERCOT there are proposals to introduce ramping and other system service products **Hepco (the utility in
Hokkaido) is vertically integrated – there are no markets for system services. As Hepco owns the generation, it instructs the power
stations to provide the necessary system services.
Source: Respective System Operators and Mott MacDonald
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German TSO Grid Control Agreement:
The German TSOs used to dispatch secondary reserves (used to account for forecast errors in supply and
demand and to restore frequency during contingencies) independently of each other – leading to a
situation in which TSOs would be calling reserve in opposite directions. In 2008 three of the four TSOs
implemented the Grid Control Cooperation (GCC) agreement, which optimises the use of automatic
reserves. The agreement was extended to include all TSOs. The GCC was implemented in four stages15:
1. Netting of power imbalances to prevent counteracting reserve activation.
2. Common dimensioning of control reserve allowing TSOs access to commonly held reserve.
3. Common procurement of secondary reserve, allowing for competition between providers across the
whole of Germany.
4. Cost optimised activation of reserve on the basis of a German wide merit order for reserves.
Figure 6.9: Use of secondary and tertiary reserves before and after TSO collaboration
Source: GE Energy
Key message: German TSOs reduced the required use of secondary reserves by implementing the Grid
Control Cooperation agreement
15 https://www.regelleistung.net/ip/action/static/gcc
0
100
200
300
400
500
600
700
800
Before After
Cap
acit
y (M
W)
Secondary - up
Secondary - down
Tertiary - up
Tertiary - down
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The German TSOs extended their Grid Control Cooperation agreement to accept foreign TSOs, creating
the International Grid Control Cooperation (IGCC) agreement. The IGCC works in a similar way to the
original GCC, in that the TSOs cooperate on the use of secondary reserves. However, currently Germany
optimises its own reserves before considering reserves from its IGCC members. There are six IGCC
members (in addition to the four German TSOs):
Energinet.DK, Denmark – joined in October 2011
Swissgrid, Switzerland – joined in 2012
Dutch Tennet, the Netherlands – joined in February 2012
CEPS, Czech Republic – joined in June 2012
Elia, Belgian – joined in October 2012
Austria – joined in 2014
For each international participant, the savings expected have been estimated to be in the order of €10
million per year.
CAISO ramping product:
California implemented a trial system service product called Flexible Ramping Constraint to deal with an
increased need for ramping, partly due to VRE. CAISO (the Californian system operator) estimates the
need for ramping between 15 minute real time commitment and 5 minute dispatch, and then applies the
need to hour ahead unit commitment and real time dispatch (GE Energy 2012). If ramping capability is
needed CAISO removes the units (generation or demand) from their commitments (electricity and system
service markets) so that they are available for ramping.
ERCOT Responsive Reserve Service: In 2002, ERCOT first allowed demand side participation in its
Responsive Reserve Service (RRS)16, equivalent to primary reserve, to respond to system events. Load
with under frequency relays17 can participate. ERCOT procures 50 percent of the required RRS from
demand response in this way.
System service reform: ERCOT and Ireland (EirGrid 2012) are in the process of significant reform of
system services. Both have plans under consideration to introduce new products including System Inertial
Response (SIR), Fast Frequency Response (FFR) and ramping products. Plans for SIR would remunerate
providers of inertia, providing additional incentive for conventional generators to run at very low output to
keep inertia on the system. EirGrid suggests that synchronous compensators could participate in this
service18. FFR is resource that can provide a faster response than primary reserves. ERCOT is currently
piloting a FFR services.
16 ERCOT is required to provide enough RRS to cover the two largest generation trips, which amounts to over 2.5 GW
17 Under frequency relays monitor the frequency of the power system and shut down the load when frequency drops below a specified threshold
18 Synchronous compensators are effectively synchronous generators that do not provide active power. They use power from the grid to spin a rotating mass at system frequency. This provides inertia to the system. They can also provide reactive power and voltage support
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Figure 6.10: System service reform in ERCOT
Source: ERCOT and Mott MacDonald
Key message: ERCOT’s proposed reforms seek to address inertia concerns by creating a System Inertial
Response that explicitly places a value on inertia.
The focus that these two, synchronously independent jurisdictions (ERCOT and Ireland) are putting on
inertia and fast frequency response suggest synchronously independent jurisdictions will have an
increasing issue with providing adequate inertia when integrating high levels of VRE.
Reform will create new products in the system service market for System Inertial Response (SIR) and Primary Frequency Response (PFR)
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Danish VRE in the regulating market – 2012: There is a Nordic regulating market that Energinet.DK can
call on to cover shortfalls or overproduction of energy on the day of operation. Participants offer bids for
upward and downward regulation stating the volume (in MW) and price (DKK/MWh). Wind power is
allowed to participant in the regulating market, and recent changes mean wind generators do not have to
offer a volume, just state their installed capacity, and so Energinet.DK calculates the forecasted offer. This
change allows for easier access to the VRE market for wind generators.
6.5.1 Capacity and flexibility markets
Although not strictly characterised as a mechanism for providing system services, there has been
increasing interest in recent years in capacity markets as a means of remunerating firm and dispatchable
generation capacity on power systems. GB is implementing a market now (Redpoint 2013) and Germany is
considering one also. This is seen as the mechanism to address generation adequacy concerns although
there is a debate as to whether capacity markets should also be designed to ensure there is sufficient
capacity available to offer flexibility.
Depending on how values are set capacity markets can in principle provide significant income to low
loaded generating plant, so addressing the issue of “missing money”. There are many different design
options but all of them will to a greater or lesser extent risk dampening wholesale energy prices. Also,
based on existing precedents and current plans all these capacity markets treat capacity as homogenous,
although reliability is generally rewarded. There is no differentiation for flexibility, which is currently only
rewarded in energy markets and system service contracts. In sum, capacity markets present a blunt
instrument for encouraging flexibility. Even so there is growing political and industry support for such
measures and the European Commission may have to accept such schemes, even though capacity
mechanisms are inconsistent with its Target Model.
An alternative non-market option is some kind of strategic flexible reserve which could be procured by
competitive tender for long term contracts and would support plant with particular flexibility characteristics.
This could be targeted for new plant or legacy plant under shorter term contracts (though this is not being
considered in any of the case study jurisdictions - although the UK government had initially considered
such a mechanism, see DECC’s Impact Assessment in 2011). Finland and Sweden do have such
systems, while Belgium is considering one. This would almost certainly work out at a lower cost than a
broader based capacity mechanism; however it may not resolve the “missing money” for assets that were
unsuccessful in the strategic reserve tender. There is little experience of such mechanism and relatively
little enthusiasm for such schemes in OECD jurisdictions.
In the last two years within Europe there has been increased discussion about introducing an explicit
flexibility market, beyond traditional system service markets (RAP 2012, Woodhouse 2014). This would
provide some mechanism for rewarding the dispatch flexibility of generating plant and also storage and
demand side. The challenge here becomes defining the performance criteria on which to reward flexible
resource owners.
Flexibility could in principle be rewarded through ensuring prices in energy and balancing markets reflect
the true costs and value of scarcity. This implies marginal balancing prices, uncapped intraday prices and
negative pricing. This could potentially be supported by new system service products, which could be
procured through a range of spot markets and tendering arrangements. This is the combination favoured
by the designers of the European Target Model.
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6.6 Grid representation
The dispatch of power generation capacity must take grid constraints into consideration. This is often done
after the market has closed, and the system operator re-dispatches as required to take account of
constraints. In more sophisticated markets, areas that have significant constraints between them can be
split to create separate pricing zones. Advancement on zoning is to use Locational Marginal Pricing (Sahni
2012), in which hundreds or thousands of pricing nodes are created to represent grid constraints.
The advantage of representing grid constraints in the market is that it provides a locational aspect to the
price signal. This can provide operational benefits – a single price distorts the incentive signal for
generators as power plants can only serve demand that has enough transmission capacity between them.
Locational pricing also influences investor decisions, encouraging deployment of flexible generation and
VRE generation (if VRE is exposed to market prices) in locations with high prices.
The majority of the case study jurisdictions do not represent grid constraints in the market at all, having a
single market price for the whole of the jurisdiction (see Table 6.6). Only California and ERCOT have LMP,
both of which were developed from zonal pricing. It may be the case that ERCOT introduced LMP because
there are specific concerns about congestion in the jurisdiction (ERCOT report a ‘4’ for the perception of
the severity of the congestion challenge).
Table 6.6: Grid representation in the market
Grid representation
Alberta Single price
California LMP
ERCOT LMP
Ontario Single price
Denmark Market split East and West Denmark – part of a wider zonal market with Norway, Sweden and Finland
Germany Single price
GB Single price
Ireland Single price
Spain Single price – part of Iberian market with Portugal which sometimes results in market splitting
Hokkaido Single price
Source: Respective System Operators and Mott MacDonald
ERCOT introduction of Locational Marginal Pricing: in 2010 ERCOT underwent significant reforms of the
energy market, introducing Locational Marginal Pricing (LMP), moving from a zonal market (of five regions)
to a nodal market (of over 4000 nodes – Figure 6.11).
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Figure 6.11: ERCOT reform from zonal pricing to Locational Marginal Pricing
Source: ERCOT and Mott MacDonald
Key message: In 2010, ERCOT moved from zonal (four pricing zones) pricing to Locational Marginal
Pricing (over 4,000 pricing nodes).
In an LMP market, the unit commitment is resolved separately for each node (J Zarnikau 2014). If there is
a transmission line between two nodes that reaches full capacity in dispatch, and no more energy can flow
done the line, there will be a price differential between the nodes. The overall effect is thousands of
different prices, taking into account the internal constraints of the transmission system, as opposed to a
small number of zoned prices. Figure 6.12 shows the pricing contours (of one specific price interval) for
both a zonal estimate (on the left) and the fully nodal pricing solution (on the right). The nodal market gives
a much higher level of granularity than zonal which improves the efficiency of dispatch, reduce overall
prices and provide pricing signals for the investment of transmission and for the location generation that
takes into account grid constraints. The benefits of LMP can influence VRE integration by reducing the
potential for wind curtailment, incentivising transmission development and incentivising VRE deployment in
high price areas. However, introducing LMP can cause problems of reduced market liquidity and increased
market power.
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Figure 6.12: ERCOT zonal Vs nodal (LMP) grid representation
Source: Public Utility Commission of Texas
Key message: ERCOT’s LMP market provides greater granularity for locational pricing and represents grid
constraints in the market price signal. This type of market representation of the grid incentivises
infrastructure development in the required places, locational value of generation and may increase
dispatch efficiency.
Germany, by contrast, is a single bidding price area (or zone) with a north to south transmission constraint.
In the initial unconstrained dispatch schedule, all of the lower offers are taken to meet demand, regardless
of whether or not this breaks physical transmission constraints. Re-dispatch by the TSOs takes constraints
into account, the most common case in Germany is when there is significant wind generation (primarily in
the north), the price is too low for the CCGT plants in the south to dispatch, and so only the wind and
northern coal plants schedule to dispatch. However, this breaks the transmission constraints, so in re-
dispatch, the TSOs must constrain the coal plant (which comes at a cost) and dispatch up the gas plant to
satisfy the constraint. The German method therefor does not dispatch efficiently as LMP, nor does it
provide locational price incentives for the development of new generation or transmission.
6.7 Interconnector management
Interconnection between jurisdictions can play a key role in integrating VRE by allowing jurisdictions to
share flexible resource and to aggregate VRE generation over a wide area. However, to maximise the
benefits of interconnection, interconnectors must be managed appropriately.
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In some cases, interconnector capacity is scheduled far in advance of operation (from day ahead to
months and even years) for historical reasons; reducing the potential role that interconnection can have in
managing variability of VRE. Interconnectors can be integrated into markets in varying degrees, moving
towards full integration of interconnectors by coupling markets. The main costs of interconnection
management are the costs of the interconnectors themselves.
The jurisdictions in the study have a varied approach to interconnector management19 (see Table 6.7). As
would be expected, the general rule is that jurisdictions with more interconnection have better
interconnector management.
Table 6.7: Interconnector management in case study jurisdictions
Interconnector management Use of interconnectors for balancing?
Alberta [information not available]
California Full integration in the spot market x
ERCOT Full integration in the spot market x
Ontario Partial integration into spot market* x
Denmark Market coupling
Germany Market coupling x**
GB Day ahead auctions
Ireland Long term and ad hoc agreements with GB, RoI and NI markets were coupled under the Single
Electricity Market (SEM) in 2007
Spain Market coupling
Hokkaido*** Long term and ad hoc agreements
*Interconnectors treated as resource in hour ahead scheduling, but not in five minute dispatch. **Germany is part of the IGCC which
means that neighbours do not balance against each other; however this does not yet allow them to use the interconnector for
balancing. ***The use of interconnectors in Hokkaido is prioritised for VRE in the case of congestion.
Source: Respective System Operators and Mott MacDonald
European market integration: one aspect of the European target model is to work towards the goal of a
fully integrated European day ahead market in which interconnector capacity is auctioned implicitly, via use
of a single algorithm.
The process is for initial price coupling of countries first, then regions as more countries join and then to
couple the regions together to a single European market (see Figure 6.13)
19 Interconnector management refers to the arrangements made to schedule and allocate the use of transfer capacity offered by interconnection between jurisdictions.
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Figure 6.13: European market coupling aims
Source: European Market Coupling Company
Key message: European Market coupling aims for a single European market, using market coupling of
regions as an interim step.
The benefits of market coupling are greater efficiency of interconnector use (access to flexible resource),
reducing perverse flows, reduction of price volatility, greater pricing convergence and overall reduction in
use of most expensive generation leads to greater social welfare. These benefits can lead to more
successful integration of VRE by:
Improves the efficiency of the use of interconnector capacity, allowing for greater access to lower cost
flexibility
Should lead to reduction in the average prices for consumers, or savings can be used for other
measures to integrate
Aggregation of VRE over larger area reduces forecast error and variability
Longer term, should reduce required capacity margins, as national markets will be able to share
capacity
However, there are barriers to market integration. Aspects of market rules must be harmonised, IT issues
can cause problems with implementation. Adequate interconnection needs to be developed. The
distribution of welfare gains and the potential for stakeholder resistance needs to be addressed (for
example, expensive generator in high priced national market may lose out in market integration,
consumers in low priced region are likely to see some increase in prices).
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To date, the landmarks of the process have been:
1999/2000 Denmark couples with Nordic regions.
In 2006 ‘Trilateral trading’ of Benelux (Belgium, the Netherlands and Luxemburg).
2007 single electricity market in Ireland (coupling Republic of Ireland and Northern Ireland).
2007 MIBEL fully launched, coupling Spain & Portugal
2008 European Market Coupling Company (EMCC) formed as a joint venture of Nord Pool Spot,
European Energy Exchange (EEX), 50 Hertz, Tennet and Energinet.DK. EMCC couples German,
Austrian and Nordpool via Denmark. Coupling had to be re-launched in Nov 2009 after initial IT
problems.
2010 – Central West Europe (CWE) region (Dutch, Luxembourgish, Belgian, French, German and
Austrian) coupling with Nordic region.
2011 Italy and Slovenia couple their markets.
February 2014 Price coupling of North West Europe (NWE) region – (CWE, Nordpool, Baltic and GB)
May 2014 MIBEL couples with NWE region
Using interconnection for balancing, the GB case: In 2009/10, Great Britain introduced the BALIT
mechanism which allows interconnection capacity with France to be used for balancing. Transmission
system operators exchange prices to change the transfer across the interconnection between jurisdictions.
The firm price is exchanged day ahead and exchanges can happen during the operating hour. The prices
for exchanged have to be costs reflective (TSO cannot profit from the exchange) and the service can be
withdrawn if system security is at risk. Cost saving in 2009/10 was estimated by National Grid to be £34
million.
6.8 Regulatory incentives on System Operators
In some jurisdictions, incentives encourage operators to manage costs efficiently and provide a conducive
network environment for VRE deployment and operation. The incentives can include mechanisms to
reward the system operator and network operators for managing their controllable costs and facilitating
VRE deployment and generation. System operator incentives may in principle drive more efficient
matching of supply and demand, so reducing demand for flexibility, while transmission incentives may lead
to increased VRE supply.
Most system operators in OECD jurisdictions face standard rate of return or price control regulations like
the transmission companies, most of which they are part of. A few jurisdictions; Ireland, Germany and
Great Britain have explicit incentive mechanisms, whereby the allowable revenue is dependent on their
achievement of cost targets. Great Britain has the longest record here and has gone the furthest along the
incentives road.
Where jurisdictions have an Independent System Operator (ISO), which is separated from transmission
owner and operator, then by definition the allowable revenues of such an entity tend to be based largely on
its operating costs rather than on its asset base, which will be small. In most cases the allowable revenues
are negotiated between the ISO and regulatory authorities (often with key system users represented at the
negotiations). It is never the less possible for a regulatory body to set an explicit incentive mechanism,
which allows the ISO to earn a reward/ bear a penalty depending on whether it achieves an agreed target.
Otherwise, the standard mechanism for setting revenue is cost past through, although in a few cases
regulators may negotiate with the SO to set caps on costs. The revenue setting arrangements are often not
transparent so our assessment in Table 6.8 must be considered indicative.
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Table 6.8: Regulatory incentives on system operators
Type of regulator incentives
Alberta Negotiated revenue cap
California Negotiated revenue cap
ERCOT Negotiated revenue cap
Ontario Negotiated revenue cap
Denmark Price control regulation
Germany Price control regulation plus some explicit incentives to reduce costs
GB Explicit incentives to reduce costs
Ireland Price control regulation plus some explicit incentives to reduce costs
Spain Price control regulation
Hokkaido Rate of return regulation
Source: Respective System Operators and Mott MacDonald
6.8.1 GB system operators incentives
Great Britain’s National Grid (NG) first faced an incentive scheme in 1994 through the Uplift Management
Incentive Scheme (UMIS), which targeted system balancing costs and was attributed for bringing down
constraint costs in the second half of the 1990s. NG now faces four incentive schemes:
Balancing Services Incentive Scheme (BSIS); a successor of UMIS, which incentivises the optimisation of
system balancing costs including management of constraint costs. The current scheme which runs over
2013-15 has three key cost components (energy, constraints and black start) which are combined to create
a total cost. This total cost is compared to a modelled target cost to determine National Grid's performance
against the incentive scheme. Whatever NG over or under spends, compared to the target cost, is shared
with the industry at a rate of 25%. This over/under spend is capped at £100m, so that the maximum profit
or loss NG receives is +/-£25m.
Wind Generation Forecasting – introduced in 2013, this scheme incentivises the reduction in the day
ahead wind generation forecasting error. The incentive has set four targets, winter and summer for both
2013/14 and 2014/15, based on the Mean Absolute Error (MAE)20 – see Table 6.9. National Grid can gain
£250k per month by achieving 0 percent error, or lose £250k if the MAE is double the target.
Table 6.9: National Grid wind forecast error targets
Year Summer MAE target (%) Winter MAE target (%)
2013/14 6.25 4.75
2014/15 6.00 4.50
Source: National Grid
Transmission Losses – NG faces a reputational incentive to publish additional information on losses on the
electricity transmission system. Previously, NG had a financial incentive; however this was dropped, as
Ofgem (the regulator) judged NG had limited control over losses.
20 The Mean Absolute Error is an average of all the absolute errors
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SO Innovation Roll Out Mechanism – This scheme provides funding to enable the roll-out of proven SO
innovation projects which deliver benefits to the environment and consumers.
6.9 Summary of measures
In this section, we rate and compare the implementation of measures in the case study jurisdictions (see
the star charts in Figure 6.14, Figure 6.15, Figure 6.16 and Figure 6.17). While each of the jurisdictions is
using a unique combination of integration measures it is possible to identify the main focus in each
jurisdiction – see Table 6.10. Annex A shows the basis for the star rating that has been applied, although
this is interpreted as a guide. The figures are subjective based on our view on progress made relating to
different types of measures. Note that the size of the start does not signify the level of VRE deployment.
In this analysis, we have split the jurisdictions into two groups: market based power systems and vertically
integrated monopoly utilities. For a market system, investment is made on the basis of the potential
revenues a generator may accrue from sales of energy, ancillary services and additional payments that
may be received. Policy makers can influence and reform market design (such as changing price caps,
negative pricing etc.) in order to encourage investment that will meet needs of the power system (resource
adequacy, system flexibility, renewables targets etc.). The development of the power system depends on
the actions of the market participant responding to the design of the market. In theory, a vertically
integrated utility in which decision makers are incentivised to act in the public good should lead to the
same result as an efficient functioning market.
In a vertically integrated utility, the utility responds to the goals (such as RE targets, generation expansion)
defined by policy makers and makes investment decisions by attempting to minimise costs while operating
with specific constraints (such as environmental and price constraints). The development of the power
system depends on the processes the utility takes in determining investment decisions.
6.9.1 Market based power systems
Figure 6.14: Alberta (left) + CAISO (right)
Source: Mott MacDonald from Case Studies
0
1
2
3
4
5
Dispatchsophisticationand maturity
VRE incentivesand dispatch
Use offorecasting
System servicesmarket
Gridrepresentation
Interconnectormanagement
Regulatorincentives on
SO
Grid code
Chart Title
Start year Now
0
1
2
3
4
5
Dispatchsophisticationand maturity
VRE incentivesand dispatch
Use offorecasting
System servicesmarket
Gridrepresentation
Interconnectormanagement
Regulatorincentives on
SO
Grid code
Start year Now
0
1
2
3
4
5
Dispatchsophisticationand maturity
VRE incentivesand dispatch
Use offorecasting
System servicesmarket
Gridrepresentation
Interconnectormanagement
Regulatorincentives on
SO
Grid code
Chart Title
Start year Now
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Figure 6.15: ERCOT (left) + Ontario (right)
Source: Mott MacDonald
Figure 6.16: Denmark (left) + Germany (right)
Source: Mott MacDonald from Case Studies
Figure 6.17: Great Britain (left) + Ireland (right)
0
1
2
3
4
5
Dispatchsophisticationand maturity
VRE incentivesand dispatch
Use offorecasting
System servicesmarket
Gridrepresentation
Interconnectormanagement
Regulatorincentives on
SO
Grid code
Start year Now
0
1
2
3
4
5
Dispatchsophisticationand maturity
VRE incentivesand dispatch
Use offorecasting
System servicesmarket
Gridrepresentation
Interconnectormanagement
Regulatorincentives on
SO
Grid code
Start year Now
0
1
2
3
4
5
Dispatchsophistication and
maturity
VRE incentives anddispatch
Use of forecasting
System servicesmarket
Grid representation
Interconnectormanagement
Regulatorincentives on SO
Grid code
Start year Now
0
1
2
3
4
5
Dispatchsophisticationand maturity
VRE incentivesand dispatch
Use offorecasting
System servicesmarket
Gridrepresentation
Interconnectormanagement
Regulatorincentives on SO
Grid code
Start year Now
0
1
2
3
4
5
Dispatchsophisticationand maturity
VRE incentivesand dispatch
Use offorecasting
System servicesmarket
Gridrepresentation
Interconnectormanagement
Regulatorincentives on
SO
Grid code
Start year Now
0
1
2
3
4
5
Dispatchsophisticationand maturity
VRE incentivesand dispatch
Use offorecasting
System servicesmarket
Gridrepresentation
Interconnectormanagement
Regulatorincentives on
SO
Grid code
Start year Now
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Source: Mott MacDonald from Case Studies
Figure 6.18: Spain
Source: Mott MacDonald from Case Studies
Table 6.10 summarises the key focus of the jurisdictions over the assessment period.
Table 6.10: Key focus of jurisdictions
Jurisdiction Key focus of jurisdiction
Denmark Interconnector management, dispatch sophistication, energy sector coupling and VRE incentives
Ireland Grid code and system services
ERCOT Grid representation and dispatch sophistication
Great Britain Interconnector management and regulatory incentives
Alberta Dispatch sophistication, grid code and VRE incentive
Ontario Grid code
Germany Interconnector management, dispatch sophistication and grid code
Spain VRE incentives and dispatch and use for forecasting
CAISO Grid representation and grid code
Source: Mott MacDonald
The star charts show that in all cases where the current position is compared with a start year there has
been an extension in the reach of the measures, so the frame conditions are becoming more supportive of
VRE. This trend is most notable in ERCOT, Ireland, Denmark, Germany and Spain. ERCOT has the most
broadly based and developed frame conditions, although it has lacks strong rules on interconnector access
and regulatory incentives on system operation performance.
0
1
2
3
4
5
Dispatchsophisticationand maturity
VRE incentivesand dispatch
Use offorecasting
System servicesmarket
Gridrepresentation
Interconnectormanagement
Regulatorincentives on
SO
Grid code
Start year 2014
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Other points to note are:
All jurisdictions are deploying measures to improve interconnector access and use, even
synchronously independent Ireland (and ERCOT to a lesser extent), but Denmark and Germany have
gone the furthest.
Ireland, Germany and ERCOT have the most sophisticated dispatch arrangements.
Ireland, ERCOT and Denmark are leading on refinement and application of new system services.
Only GB, Germany and Ireland’s regulators are applying explicit incentive mechanisms to system
operators; others are working with traditional profit or price control caps.
The application of forecasts has become more sophisticated over time with many jurisdictions seeing
high scores (including ERCOT, Ireland, GB, Denmark, CAISO, Alberta and Spain).
Only ERCOT and CAISO are using a complex grid representation, most others have undifferentiated
markets, although several are now part of wider multi-national coupling arrangements (GB, Germany
and Denmark).
6.9.2 Vertically integrated monopoly utilities
As discussed above, HEPCO is a vertically integrated utility and as such is fundamentally different to a
market based system. Our rating system has been developed to assess the integration policies in market
systems and so is not directly transferable, as they are market based. Therefore we do not show a star
diagram for Hokkaido, as we have not been able to represent the measures Hepco has taken (such as
direct investment in battery and pumped storage) to integrate VRE.
6.10 How measures address the challenges
Policy makers and system operators will need to implement a suite of measures in order to address the
integration challenge; Table 6.11 shows the key challenges that are addressed by each measure.
Table 6.11: List of measures and challenges
Frame conditions Measure
Ine
rtia &
fre
qu
en
cy
Ra
mp
ing
Tra
ns
ien
t
sta
bility
Re
ac
tive
p
ow
er
Co
ng
es
tion
Su
pp
ly
Ad
eq
ua
cy
Dispatch sophistication and maturity
Shorten programme unit times *
Shorten gate closure/dispatch times
Demand participating in spot market
Storage participating in spot market
Increase price caps
**
Allow negative pricing
VRE providing active power and frequency control
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Frame conditions Measure
Ine
rtia &
fre
qu
en
cy
Ra
mp
ing
Tra
ns
ien
t
sta
bility
Re
ac
tive
p
ow
er
Co
ng
es
tion
Su
pp
ly
Ad
eq
ua
cy
Grid codes High wind ride through
Reactive power support
Fault-ride through
Emulated inertia
Grid representation
Zonal market
Introduce LMP
VRE incentives and dispatch
Increase exposure to energy market
Increase exposure to imbalance risk
Reduce compensation for curtailment
VRE dispatch
Explicitly incentivise geographical distribution of VRE
Designate renewable zones
Interconnector management
Integrate interconnectors into DAM (if AC)
Integrate interconnectors into intra-day market
(if AC)
Use interconnectors for balancing (if AC)
Full market coupling
(if AC)
Regulator incentives
Introduce explicit cost reduction targets for the SO
System services market
Demand as emergency response
Storage as emergency response
Demand participating in Ancillary services
Storage participating in Ancillary services
Increase sophistication of system services market
Introduce capacity market
$
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Frame conditions Measure
Ine
rtia &
fre
qu
en
cy
Ra
mp
ing
Tra
ns
ien
t
sta
bility
Re
ac
tive
p
ow
er
Co
ng
es
tion
Su
pp
ly
Ad
eq
ua
cy
Use of forecasting
Centralised forecasting
Introducing the use of forecasting into
calculations for AS requirements
Use of ramping forecasts
*Only on short timescale ramps, not so with multi-hour ramps **Scarcity pricing should incentivise more flexible generation, which can
help to address ramping concerns
Source: Mott MacDonald
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This study has set out to explore how the characteristics of a jurisdiction (context) influence the challenge
of integrating variable renewables and choice of measures applied and their effectiveness. In this final
chapter we bring together the main findings under four sections:
How context drives approach
How context influences applicability and effectiveness
General lessons and recommendations for policy makers
Suggestions for further work
7.1 How context drives approach to VRE integration
One clear overall conclusion is that context matters in shaping the choice of measures, and that this
influence can be seen through four dimensions:
Level of interconnection
Access to internal flexibility21
Size and nature of VRE portfolio
Spatial pattern of VRE
The first two dimensions relate to the characteristics of the system itself and so define the foundation, with
the VRE size and spatial aspects sitting on top, as characteristics of the VRE deployed. The first two
dimensions can be plotted on a two-by-two matrix in which one can view the position any jurisdiction and
the nature of challenges it is likely to face. Figure 7.1 shows level of interconnection on the horizontal axis,
with a synchronously independent system on the right hand side and a well interconnected system on the
left hand side. The vertical axis shows internal flexibility with low flexibility at the top and high flexibility at
the bottom. With this arrangement the top right box is most challenging – jurisdictions in this area need to
do a lot of everything. Ireland is the closest example of such a context in the jurisdictions considered in this
study, although it has reasonable internal flexible resource. In contrast, jurisdictions in the bottom left box
will have a much easier time; they only need to implement easier measures, including interconnector
access items. Denmark is a good example of such a jurisdiction.
21 The size of the power system is important in this respect, in achieving economies of scale. The amount of reserve capacity required, relative to power system size, should decrease as the power system grows.
7 Conclusions and recommendations
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Figure 7.1: Context as defined by nature of interconnection and access to internal flexibility
Source: Mott MacDonald
The bold blue arrows in the figure show the main policy aim for jurisdictions in the upper boxes: all will
have a greater or lesser incentive to increase internal flexibility. The right-to-left (dashed) arrow in the
centre reflects a long term objective to increase interconnector capacity, although there is in practice a
practical limit to connecting some synchronously islanded systems. The high losses involved in subsea AC
cables make such interconnectors unviable, so DC is preferred: but this does not provide synchronous
coupling.
s one would expect, the magnitude of the VRE integration challenge and the choice of measures applied is
seen to depend on the size and nature of the VRE portfolio. Jurisdictions with higher levels of VRE
penetration will tend to require a wider range of interventions. And in systems where wind or solar is
predominant there will be different challenges which will call for different responses. These issues are
explored more fully below in section 5.
The influence of the spatial context is more straightforward. Other than building new network capacity, grid
bottlenecks can be addressed by a combination of mechanisms which put a scarcity price on constraints
and so shift dispatch in a way that optimises the use of limited grid capacity. This could be complemented
by new operational measures like dynamic line rating (DLR) and flexible security standards (holding less
capacity aside under certain conditions). In the longer run, the same price signal should provide evidence
for the value of new grid capacity and/or VRE deployment.
D
Weakly connected
High internalflexibility
Well interconnected
Low internalflexibility
Easy
Challenging
Will need to consider all measures
Implement easy measures including interconnector access
Long termPossibility
Polic
y ai
m
Polic
y ai
m
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Figure 7.2: Approaches to VRE integration under different contexts
Source: Mott MacDonald
Figure 7.2 shows how the general approach to VRE integration is shaped by the system characteristics
with highly interconnected systems focusing on interconnector access while islanded systems focus on
improving internal flexibility. It also shows that “extra measures” are more likely to be required earlier in the
more demanding situation of islanded systems. In this diagram, the interconnection dimension is expanded
to three categories, with a weakly interconnected category between the strongly interconnected and the
synchronously independent ones.
7.2 How context influences applicability and effectiveness
7.2.1 Introduction
This section outlines which measures have been shown to be applicable and effective in different contexts.
As previously outlined the main focus is on what is applied and general perceptions of effectiveness rather
than specific and quantified estimates of effectiveness, as the latter is not available. This discussion is
arranged under the same four dimensions of the context as described above.
Synchronouslyindependent
WeaklyInter-connected
StronglyInter-connected
• Grid code• Dispatch
rules• VRE
incentives• New system
services• Use of
forecasting• Grid
represent-ation
• Regulatory incentives
Incr
easi
ng
VR
E p
en
etra
tio
n
Focu
s o
n b
est
use
of
inte
rco
nn
ect
ors
Focu
s o
n im
pro
vin
g ac
cess
to
inte
rnal
fle
xib
ility
Bal
ance
d f
ocu
s
“Extra measures”
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7.2.2 Interconnection with other systems
Jurisdictions with higher levels of interconnection tend to use interconnectors as a key measure for
integrating VRE through accessing a much larger market. This allows access to other systems’ inertial
response and flexible resources as well as the pooling of VRE output (so reducing the variability of overall
VRE). A small system with a high VRE share can therefore “piggyback” on a larger system, assuming this
does not itself have a high VRE share. Denmark, while implementing integration policies, has been able to
take advantage of its location within Europe to successfully integrate a large amount of VRE.
In contrast, synchronously independent systems are developing additional system services in order to
remunerate providers of inertia and fast frequency response to ensure system stability at high levels of
VRE.
7.2.3 Internal flexible resources
Systems with large amount of flexibility have a comparatively easy task of accommodating high levels of
VRE. These jurisdictions tend to focus on ensuring there are appropriate incentives for flexible resources
and that sophisticated forecasting and scheduling/despatch algorithms are applied so as to reduce reserve
and balancing costs.
Jurisdictions which lack adequate access to internal flexibility may suffer problems even at low VRE
penetration levels which may lead to VRE being curtailed as has happened in Ontario, where there is large
tranche of inflexible baseload nuclear and inflexible hydro. Ontario has introduced a special alert service to
allow it to better manage this situation.
7.2.4 Size and the nature of VRE portfolio
The size and the shape of the VRE portfolio matter, as we discuss below:
Systems which experience high spot shares of VRE in total generation tend to face greater challenges in
terms of ramping and inertial and frequency response. Commonly applied measures are application of
sophisticated forecasting/despatch techniques, and incentives for provision of flexibility and
rules/incentives to encourage system friendly VRE deployment. Where there are preferential offtake
arrangements (whether premiums or feed-in-tariffs), negative pricing may be required to deter some
discretionary generation and/or encourage uptake via exports, DSR and charging storage. The alternative
is curtailment (which can be indirect or through direct dispatch control).
More generally, it is apparent that as the level of VRE penetration increases to high levels, the special
treatment of VRE tends to be reduced. Financial support and protection from imbalance penalties is
reduced, dispatch priorities are weakened and full (or near full) compliance with grid codes is required.
Central (SO) dispatch control of wind is another measure that can be employed to achieve efficient use of
VRE.
The mix of VRE matters too, although different jurisdictions response varies depending on the broader
context (level of interconnection and access to internal flexible resources).
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Solar PV tends to have lower visibility than wind to SOs, because it is generally deployed at much smaller
scale and so monitoring and metering requirements are less onerous. Jurisdictions with high solar shares
are beginning to experience (or are forecasting) high ramping requirements especially in evenings (when
PV output falls and evening load rises). At the same time a number of jurisdictions (Germany, Spain and
Ontario) are also experiencing reverse power flows during peak solar hours in parts of their distribution
networks which are being addressed by updating control systems and temporary operational changes.
Several jurisdictions (ERCOT, CAISO, Hokkaido and Germany) are supporting pilot projects for
deployment of electricity storage installed at or close to PV sites. Indeed, some US jurisdictions (most
notably California) and Germany are seeing an emerging consumer led demand for batteries and smart
controls for PV.
7.2.5 Spatial aspects
Where deployment of VRE is concentrated geographically and away from the main load centres this can
present a challenge in terms of network congestion. A number of jurisdictions have had to address this
issue. In Texas, ERCOT has replaced a zonal market arrangement with a nodal one that more clearly
identifies the physical transmission constraints through the more granular pricing. This allows a more
efficient dispatch and provides more refined incentives for transmission owners and generators’
investment. ERCOT has also implemented Competitive Renewable Energy Zones (CREZ), to channel new
investment into preferred areas, which has eased the transmission challenge.. In GB, National Grid is
building the first of a pair of offshore HVDC lines that will enable the export of Scottish wind energy to
England, while Germany has plans for new north-south transmission axis for supplying northern wind
energy to the south and importing solar to the north.
7.2.6 Underlying trends
In addition to these contextual drivers the study has identified a number of trends in the ways measures
are applied that relate to wider technology and market development:
Grid code requirements for VRE are tending to get stricter and in the future could require synthetic
inertia, active power and frequency response and high wind ride through capabilities. This reflects
technical advances and a reduction in costs of including these capabilities as well as recognition of
their value to the SO.
Dispatch is tending to become more sophisticated – jurisdictions are shortening gate closure and/or
dispatch intervals, increasing price caps and introducing negative pricing in markets. This trend is
probably driven by learning by doing of SOs, market operators and regulators; however, it has almost
certainly been reinforced by the increased interest in trading between jurisdictions (in Europe and North
America) and the need to accommodate an increased level of renewables.
VRE generators are becoming more exposed to market forces by moving towards market premium as
opposed to FiT incentive schemes, requiring VRE dispatch, exposure to imbalance risk and reducing
compensation for curtailment. This should lead to more system friendly VRE deployment and economic
operation of the power system; however this comes with increased risk for developers and higher
associated development costs. The drivers for this trend for increased exposure to markets are clearly
the increasing penetration of VRE itself and the improvement in their competitive position.
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7.3 General lessons and recommendations for policymakers
A number of lessons can be drawn from this study, which can be considered under two broad categories:
general lessons for all jurisdictions and lessons for jurisdictions with particular characteristics. Each is
considered in turn.
7.3.1 General lessons for all jurisdictions
1) Consider deployment patterns/mix of technologies at an early stage of VRE deployment in order to
mitigate congestion/ reduce swings in net load.
Ideally, if the available resource allows it, then a mix of solar and wind will lead to a smoother profile of
VRE generation and also a more spatially diversified one, so easing congestion and impacts on net
load. This balance can be affected by a combination of differentiated financial support and planning
rules. Network connection and use of system charging could be used.
Several of the above measures could be used to guide development for a particular technology in
specific areas. ERCOT’s Competitive Energy Resource Zones (CREZ) has helped steer new wind
developments into different areas.
Use financial support mechanisms that provide some exposure to market prices – such as market
premiums - as this should encourage developers to locate in areas which do not follow the
predominant production pattern. Full market exposure clearly provides the strongest signal, but this
needs to be balanced with the need to minimise the cost of capital by giving sufficient investment
certainty.
Use permitting/ technology licensing rules to ensure that the characteristics of technology are system
friendly. This is similar to grid code requirements, but the latter are primarily required for supporting the
grid.
Ensure distribution networks are able to handle PV, through installing appropriate monitoring, metering,
controls, protection systems and planning.
2) Build-in grid code measures sooner rather than later.
Both wind and solar PV technologies have developed considerably from the stage when both wind and
PV where largely insulated from grid. In the early years, in what was then perceived best practice, the
focus was on ensuring this new generation would be cut off during disturbances to protect the wider
system. This isolation approach only made sense when VRE penetration was negligible.
The rational approach now is to ensure that VRE is built-in with as much grid support functionality as is
viable. For wind this extends from fault ride-through and frequency and reactive power support to high
wind ride through and synthetic inertia (in synchronously independent systems). Solar PV can provide
an equivalent suite of system support services.
3) Move to near real time re-dispatch supported by sophisticated forecasts
Whether systems employ near real time markets or centrally dispatched systems, it is clear that
dispatch near real time is an important aspect of ensuring an efficient dispatch process where there is
a significant VRE contribution.
A smart dispatch system will require sophisticated forecasts to improve scheduling and dispatch. A
better forecast is only valuable if one acts on it.
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4) Learn from others but do one’s own studies to assess impacts
One can learn much from others’ experience and studies; especially from comparable jurisdictions
however it is always best to run one’s own studies. Among the case study regions, Ireland and ERCOT
appear to have done most VRE integration studies, perhaps because they perceive they face a more
imminent and tougher challenge than others. Others may face an easier overall integration task but
may face issues not evident in Ireland and Texas.
5) Co-operate with other jurisdictions
Exploiting the opportunities to trade energy, reserve and balancing services to the fullest extent is likely
to be one of the best ways of integrating VRE where a jurisdiction has interconnector access to other
jurisdictions. Possible synergies between the flexibility of neighbouring countries means that even a
large system connecting to small system should see a net gain.
Co-operation on industry codes, such as Grid Codes can bring benefits to developers, technology
developers and system operators. This process is already underway in some regions: for instance,
ENTSO-E, the European association of SO is planning to implement a pan-European Grid Code
standard within which TSOs can set their own grid codes.
International (or cross jurisdiction) co-operation on the extension of interconnectors is clearly essential
for any expansion of interconnector capacity. Common agreement on support mechanisms, contracting
structures and consenting would help in deploying such assets.
7.3.2 Lessons by characteristics
1) Well-connected countries should focus on interconnector rules and market harmonisation. The first
priority should be making sure the fullest interconnector capacity is made available and applying “use it
or lose it” rules for capacity allocation. This should be followed by coupling of day ahead and intraday
markets and SO-to-SO co-operation on balancing.
2) Jurisdictions with difficult to resolve grid congestion should use zonal market or locational marginal
pricing. Jurisdictions experiencing chronic grid bottlenecks should consider both operational measures
such as dynamic line rating (and potentially special derogations in security standards) and market
arrangements which explicitly incorporate the spatial dimension in pricing. A full nodal market is the
most economically efficient; however, a zonal market can sometimes also bring a significant share of
the benefits. Both of these spatial market mechanisms will provide evidence for the value of new
transmission capacity.
3) Synchronous islands need to be aware that their challenge will be greater and consider special system
services for inertia and fast frequency response. Synchronously independent systems will need to
deploy special system services such as fast frequency response, dynamic reactive power and
emergency response to frequency drops (through DSR and storage) to ensure adequate flexibility and
system resilience – as being considered in Ireland and ERCOT. At some levels of analysis, all systems
are synchronous islands and so inertia and frequency concerns will need to be considered on the
appropriate level.
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4) Systems with low internal flexibility and weak interconnections need to be aware that they will face
caps on VRE deployment (before curtailment is required) unless they address these constraints.
Systems lacking significant flexibility (due to high shares of nuclear or inflexible coal/gas/hydro plant)
will be forced to choose between curtailing VRE or their “inflexible” dispatchable plant even at fairly low
VRE shares, as has been demonstrated in Ontario. Exploiting storage opportunities in the existing
assets, Demand Side Response (DSR) and squeezing the most out of existing interconnectors should
be first priorities, although scope here may be limited. Beyond this these systems will need to expand
storage and interconnector capacity. Increasing flexible generation capacity will only resolve
curtailment issues when the problem is an excess of inflexible energy if it is the inflexible plant being
retrofitted or displaced by the new flexible generation.
7.4 Detailed listing of measures by context
Table 1.1 provides our assessment of the importance of different VRE measures under a range of different
contexts. The measures are rated on a zero to three star basis, with three stars being of critical
importance. Our assessment is based on the finding of this survey although it is necessarily subjective. It is
important to note that our assessment applies to jurisdictions that are attempting to reach high level shares
of VRE. In this respect, it is important that the process of implementing some of the measures in done so in
a way that does not reduce investment in VRE, especially in the early stages. For example, we consider
market exposure will be important for VRE integration at high shares, however, this will increase the risk
premium and therefor cost for developers, and so may need to be done at later stages of deployment.
Table 7.1: Importance of integration measures under different contexts
Measure Easy Challenging Special circumstances
Well inter-connected/ high flex
Weakly connected/ low flex
Synchronously isolated/ high flex
Synchronously isolated/ low flex
Congested networks
High wind share
High solar share
Dispatch Sophistication
Short programme time units ** ** *** ** ** ***
Short gate closure/re-dispatch times ** *** *** ** ** **
Demand participates in sport market (or ToU pricing)
* ** *** ** ** **
Storage participating in spot market * ** *** ** ** **
High or uncapped prices across DA, intraday and balancing markets
* ** *** ** ** **
Negative prices in energy market * ** *** ** ** **
Grid Representation
Zonal market * * *
Locational Marginal Pricing ** **
Grid code
Active power and frequency control ** *** *** *** *** *
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Measure Easy Challenging Special circumstances
Well inter-connected/ high flex
Weakly connected/ low flex
Synchronously isolated/ high flex
Synchronously isolated/ low flex
Congested networks
High wind share
High solar share
High wind ride through ** ** *** *** ***
Reactive power support * ** *** *** *** *
Fault-ride through * ** ** *** *** *** ***
Emulated inertia * ** ** ** **
VRE incentives and dispatch
Increase exposure to energy market * ** ** *
Increase exposure to imbalance risk * ** *** *
Reduce compensation for curtailment * ** * *
Require VRE to dispatch in energy market
* *** * *
Explicitly incentivise geographical distribution of VRE
* * ** *** *** **
Designate renewable zone * ** ** *
Dispatch control of wind * ** *** ** *** *
Interconnector management
Integrate interconnectors into day ahead market
* ** * * *** *** ***
Integrate interconnectors into intraday market
** *** * * *** *** ***
Use interconnectors for balancing ** *** * * *** *** ***
Full market coupling * ** * * ** ** **
Regulator incentives
Explicit incentive mechanisms to achieve system cost and performance targets
* * ** * * *
System services market
Demand as emergency response * ** *** *** *** ***
Storage as emergency response * ** *** ** * *
Demand participating in ancillary services
* * *** ** ** **
Storage participating in ancillary services
* *** ** ** **
Increase sophistication of system services
* ** ** *** ** ** **
$
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Measure Easy Challenging Special circumstances
Well inter-connected/ high flex
Weakly connected/ low flex
Synchronously isolated/ high flex
Synchronously isolated/ low flex
Congested networks
High wind share
High solar share
Use of Forecasting (UoF)
Real time monitoring of VRE output * ** ** *** *** *** ***
Centralised forecasting * ** ** *** *** *** ***
Use of ramping forecasts ** ** *** *** *** ***
Use of rolling forecasts to calculate ancillary service requirements
* ** *** *** *** ***
Source: Mott MacDonald
7.5 Suggestions for further work
In conducting this study it became clear that there are numerous measures which policy makers can take
to influence the ability of OECD’s electricity systems to accommodate increasing levels of variable
renewable energy. This report maps a large number of measures – but restricts itself to those that can be
grouped under one of the eight dimensions of the frame conditions which cover market and operational
rules. We have therefore not covered policy measures relating to reducing barriers to deployment of VRE
and flexible resources: such as consenting and planning (including stakeholder engagement) and financial
support for investments and technology development. These would have significant value in developing an
extended taxonomy of measures in a way that identifies who the key agents for implementation are
(market operator, system operator, regulator/government, planning authority, etc.). Other categorisations
could also be considered.
This study has also revealed the dearth of information on the costs and benefits of measures for
integrating variable renewables. This is not entirely surprising given that many of the interventions have a
wide remit and there are many different agents for implementation. As mentioned in this report, the direct
costs of most interventions are small as they generally relate to changes in operational practices and
market rules, etc. although the indirect costs22 on market participants and network users may be more
significant. The main uncertainty here relates to the benefit side as this is very difficult to determine given
the need to define counterfactuals. All this is an area which deserves more review and analysis, as this
should throw proper light on the effectiveness of measures.
A third area to explore in further studies of measures for integrating VRE is the extent to which there is a
need for some kind of “system architect” for ensuring a properly integrated approach is applied to VRE
integration. This could involve the whole policy chain from planning and assessment studies, through
implementation and monitoring and evaluation.
22 Indirect costs such as investment in retraining, new systems, operation al practice, equipment changes may be borne by participants due to market changes
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Appendices
Appendix A. Scoring mechanism ________________________________________________________________ 73
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This appendix details the scoring mechanism used to rate the frame-conditions for each of the jurisdictions.
The scoring was applied as a guide, and professional judgement was used when applying this scoring.
Table A.1: Scoring mechanism for frame-conditions
Description
Dispatch sophistication and maturity 1 = No intraday market 2 = Intraday market with gate closure of an hour + (max 3)
3 = Intraday market with gate closure of less than one hour (+1 for negative pricing,
+1 for high or no price caps)
VRE incentives and dispatch 1 = No incentives and no deployment 2 = Straight FiT with no imbalance risk
3 = Premium incentive 4 = (almost) Full market price exposure (if economic)
5 = (almost) Full market price exposure (if economic) and dispatch
Use of Forecasting (UoF) 1 = No forecasting 2 = Centralised forecasting
(+1 UoF for scheduling, +1 UoF for calculating reserve or regulation requirement,
+1 UoF for ramping alert)
System services market 1 = No market 2 = Mostly regulated payments 3 = Mostly marginal payments
4 = Ramping product 5 = Product definition based on VRE assessment (e.g. Fast
frequency and/or inertia products)
Grid representation 1 = Single market zone 3 = Zonal 5 = LMP
Interconnector management and market integration 1 = Long term agreements and ad hoc arrangements 3 = Explicit auctioning of capacity
4 = Market coupling with all/most borders (+1 for using interconnectors for balancing)
Regulator incentives on SO 1 = Cost pass through in TSO
2 = Rate of return regulation for TSO/ cost pass through ISO
3 = Price control regulation TSO/ negotiated revenue for ISO
4 = Explicit incentives to reduce costs
5 = Performance based regulation
Grid code 1 = no specific requirements 2 = only FRT
3 = FRT, reactive power and frequency response for PV or wind
4 = FRT, reactive power and frequency response for PV and wind
5 = If requiring synthetic inertia or high wind ride through
Appendix A. Scoring mechanism
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Ancillary or system services
Ancillary or system services are additional services in an energy market which are used by system operators to provide system security in the event of generation loss (reserves) and sometimes small variations in the supply/demand balance (regulation or balancing). Additionally, other services (such as black start) may be procured by a system operator.
Congestion Congestion occurs when a section of the network reaches its transfer capacity, constraining the ability of the grid to transport energy from the source of generation to demand
Context The context of a jurisdiction is the aggregation of the jurisdiction's characteristics (Interconnectedness, level of VRE penetration, geographical distribution of VRE capacity and level of power system flexibility)
Fault Ride Through Fault Ride Through is a technical requirement of generation equipment to continue to generate in the event of fault to prevent a cascade trip of generation. FRT requirements are usually specified in the grid code of a jurisdiction.
Flexibility A general term to describe the ability of generation, storage, demand response or a whole power system to accommodate variability..
Frame condition Frame conditions are eight key categories of integration measures which policy makers can act within to influence the integration challenge
Inertia The inertia of a power system refers to the kinetic energy stored spinning mass of synchronously connected turbines.
Interconnector management
Flow of energy between jurisdictions is scheduled based around a specific set of rules relating to how the interconnector is used. These rules are referred to as interconnector management
Locational Marginal Pricing
Also known as nodal pricing, Locational Marginal Pricing (LMP), refers to the representation of internal grid constraints in a market by resolving dispatch schedules based on hundreds or thousands of nodes, as opposed to just one single price area.
Net load Net load is the difference between system load (demand) and generation from Variable Renewable Energy sources
Ramping Ramping refers to large swings in generation over minutes to hours.
Reactive power Reactive power is a necessary property of AC systems. As opposed to active power, reactive power cannot do work, but the management of reactive power is needed for system stability.
Glossary
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Resource adequacy Resource adequacy (often called generation or supply adequacy) is the ability of the power system to provide sufficient capacity to meet demand. VRE generators contribute considerably less to resource adequacy, on a MW for MW basis, than conventional generators due to their inherent uncertainty and variability.
Synthetic Inertia Synthetic inertia refers to the use of power electronics to provide a frequency response that approximates the response of real inertia. However, due to the use of power electronics (which requires monitoring and communication between equipment), synthetic inertia is not as fast as the instantaneous response from inertia.
Transient stability Transient stability is the ability of a synchronous power system to maintain synchronisation of its connected units when subjected to a severe transient disturbance such as a fault on transmission facilities (or generator trip)