integration of variable renewables -...

Integration of Variable Renewables

Volume I: Main Report

January 2015

IEA-RETD

326641 TRD EFR 5 e

Vol I: Main report

28 November 2014





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.



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



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

i 326641/TRD/EFR/5/e January 2015 Vol I: Main report


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

iv 326641/TRD/EFR/5/e January 2015 Vol I: Main report



distribution of VRE Interconnection Flexibility

Great Britain


Ireland


Spain

Hokkaido


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.

viii



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 * ** *** *** *** *

xii 326641/TRD/EFR/5/e January 2015 Vol I: Main report







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

* *** ** ** **

$

xiii








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

* ** *** *** *** ***


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

xiv



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.

xv 326641/TRD/EFR/5/e January 2015 Vol I: Main report


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

xvi



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

xvii



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



1

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



2

Figure 1.1: World map of jurisdictions in the study


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



3

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


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



4

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.



5

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



6

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.



7

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

y (M

W)

Wind production Load (consumption) Net load (Load - wind production)

1 -7 January 2014

3 Challenges for Policy Makers



8

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).



9

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.



10

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


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






Designate renewable zones


Integrate interconnectors into DAM

Integrate interconnectors into intra-day market

Use interconnectors for balancing

Full market coupling


Introduce explicit cost reduction targets for the SO




$



11

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




12

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



13

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).



14

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



15

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%

50%

60%

70%

80%

90%

100%G

erm

any

De

nm

ark

Spai

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Isla

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of

Ire

lan

d

GB

ERC

OT

Ho

kkai

do

Cal

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Alb

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Inst

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d V

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cap

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and

Solar Wind



16

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%

100%

De

nm

ark*

Cal

ifo

rnia

On

tari

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Ger

man

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Spai

n

Isla

nd

of

Ire

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Ho

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GB

ERC

OT

Inte

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nn

ect

ion

as

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eak

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and

Synchronously independent Synchronously connected



17

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



18

* 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.



19

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%

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100%

120%

140%

160%

180%

Spai

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Other Storage Nuclear Coal Hydro Oil Gas



20

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


distribution of VRE* Interconnection Flexibility

Alberta

California

ERCOT


Ontario

Denmark

Germany

Great Britain


Ireland


Spain

Hokkaido**




21

*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.


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



22

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



23

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).



24

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.



25

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.



26

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.


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.



27

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.



28

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.



29

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


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


Grid representation

Use of forecasting


Grid codeVRE incentives and dispatch

$Regulator incentives on SO

6 Measures for integrating VRE



30

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.



31

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



32

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


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



33

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



34

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.



35

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



36

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)



37

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.


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.



38

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.


Requirements for wind and solar

Requirements for wind only



39

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.



40

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.




41

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



42

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



43

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)



44

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.



45

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


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).



46

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.



47

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.



48

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.


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.



49

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).



50

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.



51

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


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



52

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



Use offorecasting


Gridrepresentation



SO

Grid code

Start year Now

0

1

2

3

4

5



Use offorecasting


Gridrepresentation



SO

Grid code

Chart Title

Start year Now



53

Figure 6.15: ERCOT (left) + Ontario (right)


Figure 6.16: Denmark (left) + Germany (right)


Figure 6.17: Great Britain (left) + Ireland (right)

0

1

2

3

4

5



Use offorecasting


Gridrepresentation



SO

Grid code

Start year Now

0

1

2

3

4

5



Use offorecasting


Gridrepresentation



SO

Grid code

Start year Now

0

1

2

3

4

5

Dispatchsophistication and

maturity

VRE incentives anddispatch

Use of forecasting


Grid representation


Regulatorincentives on SO

Grid code

Start year Now

0

1

2

3

4

5



Use offorecasting


Gridrepresentation


Regulatorincentives on SO

Grid code

Start year Now

0

1

2

3

4

5



Use offorecasting


Gridrepresentation



SO

Grid code

Start year Now

0

1

2

3

4

5



Use offorecasting


Gridrepresentation



SO

Grid code

Start year Now



54


Figure 6.18: Spain


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


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



Use offorecasting


Gridrepresentation



SO

Grid code

Start year 2014



55

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


Increase price caps

**

Allow negative pricing

VRE providing active power and frequency control



56


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 dispatch


Designate renewable zones


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)


Introduce explicit cost reduction targets for the SO




Demand participating in Ancillary services

Storage participating in Ancillary services

Increase sophistication of system services market

Introduce capacity market

$



57


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




58

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



59

Figure 7.1: Context as defined by nature of interconnection and access to internal flexibility


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



60

Figure 7.2: Approaches to VRE integration under different contexts


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”



61

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).



62

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.



63

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.



64

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.



65

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






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 ** *** *** *** *** *



66






Congested networks

High wind share

High solar share

High wind ride through ** ** *** *** ***

Reactive power support * ** *** *** *** *

Fault-ride through * ** ** *** *** *** ***

Emulated inertia * ** ** ** **


Increase exposure to energy market * ** ** *

Increase exposure to imbalance risk * ** *** *

Reduce compensation for curtailment * ** * *


* *** * *


* * ** *** *** **

Designate renewable zone * ** ** *

Dispatch control of wind * ** *** ** *** *


Integrate interconnectors into day ahead market

* ** * * *** *** ***

Integrate interconnectors into intraday market

** *** * * *** *** ***

Use interconnectors for balancing ** *** * * *** *** ***

Full market coupling * ** * * ** ** **


Explicit incentive mechanisms to achieve system cost and performance targets

* * ** * * *


Demand as emergency response * ** *** *** *** ***

Storage as emergency response * ** *** ** * *

Demand participating in ancillary services

* * *** ** ** **

Storage participating in ancillary services

* *** ** ** **

Increase sophistication of system services

* ** ** *** ** ** **

$



67






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

* ** *** *** *** ***


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



68

1. AEMO (2011), "Wind Integration International Experience - WP2: Review of Grid Codes", Australia

2. AESO (2013), "Results of Wind Dispatch Pilot", Alberta

3. AESO (2013), "Wind Integration Phase 1 Post-Implementation Review", Alberta

4. AESO (2014), "Energy Storage Integration" Alberta

5. Arup (2012). “A five minute guide to electricity storage.” Accessed November 21, 2013:

http://www.arup.com/Publications/5_minute_guide_to_electricity_storage.aspx.

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http://www.energy.ca.gov/renewables/tracking_progress/documents/renewable.pdf

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EirGrid

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Power Markets: Best Practices from International Experience NREL/TP-6A00-53732 Golden, CO:

National Renewable Energy Laboratory Accessed November 19, 2013: http://www.nrelgov/docs/

fy12osti/53732.pdf

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System from 2015 – 2020 with an Outlook to 2025" Accessed November 19, 2013:

http://www.denade/fileadmin/user_upload/Publikationen/Erneuerbare/Dokumente/Summary_dena_Gr

id_Study_IIpdf

15. Denholm et al (2008) "Production Cost Modelling for High Levels of Photovoltaics Penetration"

National Renewable Energy Laboratory Accessed November 19, 2013:

http://www.1eereenergygov/solar/pdfs/42305.pdf

16. Dent et al (2010), "Application of wind generation capacity credits in the Great Britain and Irish

systems", CIGRE Paris

17. ECAR, Australian Energy Market Operator (AEMO) (2011) “Wind Integration: International

Experience— Review of Grid Codes” Accessed November 19, 2013:

http://www.aemocomau/Electricity/ Planning/Related- Information/~/media/Files/Other/planning/0400-

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Appendices

Appendix A. Scoring mechanism ________________________________________________________________ 73



73

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



74

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.


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)