CORNWALL INSIGHT / GOWLING WLG WHITEPAPER · Cornwall Insight / Gowling WLG whitepaper \ Foreword 1 FOREWORD The electricity sector is experiencing change at a pace and of a nature

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CORNWALL INSIGHT / GOWLING WLG WHITEPAPERELECTRICIT Y MARKETS IN TRANSITIONMARCH 2018

Cornwall Insight / Gowling WLG whitepaper \

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CONTENTS

FOREWORD 1

INTRODUCTION 2

GENERATION 5

NETWORKS 15

RETAIL MARKETS AND CONSUMPTION 25

FINAL CONCLUSIONS 31

This paper discusses how technology is shaping transition in the electricity sector across different elements of the value chain: focusing on the generation, network, and retail sectors. These links, set out in the 1990s, are becoming less distinct as technology and new practices begin to dissolve the once hard and fast barriers between them.

It then considers what this transition means for industry stakeholders, including investors, operators, and consumers, and posits some thoughts on the market outlook going forward.

Cornwall Insight / Gowling WLG whitepaper \

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Cornwall Insight / Gowling WLG whitepaper \ Foreword

1

FOREWORD

The electricity sector is experiencing change at a pace and of a nature unlike anything seen before. New technologies, actors and business models are combining to transform its shape and structure beyond recognition.

Transformation is evident in every part of the value chain – how

electricity is produced stored and consumed, how it is transported,

how it is traded and how we, as consumers, engage with the sector.

Previous boundaries between generation, transportation and supply

are blurring rapidly. The days in which the sector was dominated by

a small number of major players with electricity being produced in a

limited number of large fuelled power stations and transported to a

largely passive consumer base have long since passed.

A rapid growth in, often renewable, decentralised generation, new

trading and supply propositions, and technology solutions that

allow consumers to interact directly with the market means that the

sector today looks very different to how it looked yesterday. It will

undoubtedly look very different again tomorrow.

Technology and innovation are playing a central role in the

transformation, from new means of generating and storing electricity,

systems that optimise the flexibility of assets and platforms that

allow that flexibility to be traded, to the emergence of electric

vehicles acting as both demand and potentially generation sources,

the roll out of smart meters and the rise of the “connected home” –

the list goes on. The opportunities for those looking to play a role in

the changing market are abundant.

Those opportunities expose a range of challenges however. Some of

the most important are explored in this whitepaper. If the sector is

to take full advantage of the enormous potential that technological

and business innovation has to help deliver an affordable, secure

low-carbon electricity sector, those challenges will need to be quickly

grasped. That will require policy makers and regulators, existing and

new industry participants, providers of capital and legal and financial

advisers, amongst many others, to play their part.

We have started the journey and some progress is being made. It is

important it continues apace. We hope that this whitepaper helps to

further stimulate the debate.

DEREK GOODBANPartner and Head of Energy

+44 (0)370 733 0613

+44 (0)7884 110085

[email protected]

Cornwall Insight / Gowling WLG whitepaper \ Introduction

2

INTRODUCTION

The British Electricity Trading and Transmission Arrangements (BETTA) bilateral market design, first put in place in 2001 in England and Wales and then extended to Scotland in 2005, is modelled on large power stations, close to their fuel sources, moving power down transmission cables to large centres of relatively predictable demand. Large suppliers, eventually vertically integrating with generation, provided the hub around which all industry functions were built, and financing and investment underwritten.

Just over a decade later this model is already an anachronism.

Since 2000 policy targets to decarbonise power have led to the

deployment of over 30Gigawatts (GW) of smaller scale and typically

lower carbon distributed generation of which around 10GWs is

fuelled, and the remainder a mix of mostly on and offshore wind

and PV solar. Costs – driven by global deployment – have fallen

as learning rates and engineering efficiencies have driven them far

lower, far quicker than previously imaginable. Comparing the joint

government and industry target of £100/MWh for offshore wind by

2020 to £57.50/MWh achieved in the last Contract for Difference

(CfD) auction is emblematic of this seismic shift, as is the fact that

subsidy-free routes of deployment are now opening to PV solar and

onshore wind.

The level of investment in clean energy that continues to drive this

deployment has been incredible, peaking at $360.3bn globally in

2015 and $333.5bn in 2017.1 Meanwhile the financing model has

been transformed from private equity and straightforward project

lending to include mature and sophisticated capital structures in the

form of project bonds, pension fund direct investment, and listed

‘yield Co’s’.

Rapid deployment of new low-carbon technologies has necessitated

wider innovations. As the reduction in controllable and spinning

generation on electricity systems has continued apace, it has created

issues with system inertia, frequency and wholesale market volatility.

1 Bloomberg New Energy Finance. January 20182 All-Party Parliamentary Group (APPG) on Energy Storage. December 2017

In response, we have seen major technological change: for instance,

a rapid expansion in planned battery storage, driven in part by

falling lithium costs and in part by regulatory and policy stimulus

to address the new challenges that have been spawned by the

low-carbon transition. Estimates of the pipeline of battery storage

in Great Britain range between 1.7GW to 12GW by 20212 , from a

base of near zero in 2015.

Batteries are one manifestation in a family of solutions labelled

‘smart and flexible’, encompassing not just generation but

demand response, energy efficiency and the delivery of real-time

matching across the whole energy value chain, right down to the

household level.

New actors are entering the market, from technology only players

to service providers like aggregators of all different shapes and sizes.

New models for pooling generation and demand response more

effectively, such as virtual power plants (VPPs), are emerging. The

electrification of transport is leading to a renaissance in interest in

the energy supply by oil majors such as Shell, through their purchase

of the household gas and electricity supplier First Utility in December

2017, and to exploration of the benefits of electric vehicle-to-grid

services. At the same time decarbonisation of heat is rising up the

political agenda and imposing new challenges across the energy

sector, raising important questions for networks.

Real-time trading and capability to settle production and

consumption locally, without the need for a central clearing house

(sometimes referred to as ‘blockchain’) is starting to shape how

stakeholders visualise how traded markets and electricity networks

– national, international and local – could function in the future.

Decentralised markets could profoundly change how the system

is balanced and could drive the atomisation of national markets

into smaller and more closely integrated units of operation, from

local markets to peer-to-peer relationships. Digitalisation and

technological advances in computing and data management are

opening up possibilities that would have been inconceivable just

a few years ago.


3

Policy is struggling to keep pace with the transformation. Much of

the initial response was focused on managing the impacts of change

on traditional players and legacy assets. For example, renewable

subsidies have been phased out to just two more CfD auctions

over a period of retrenchment beginning in 2013 and ending with

the capping of low-carbon levies out to 2025 in the last budget.

Capacity payments have returned to the wholesale market partly in

response to ‘missing money’ resulting from growth of renewables and

driving down wholesale electricity prices, reducing projected returns

for some renewable generators who have not benefited from the

trade-off of capacity payments. In retail supply, price caps are being

reintroduced across the customer base to address rising network and

policy costs in bills. The debate on fairness in energy markets and

protecting the interests of the disengaged and the vulnerable has

only just begun.

Regulation is also trying to respond flexibly to the changing

environment, with mixed success, as new business models and

players look to gain access to the market. Code governance and

regulatory responsiveness are increasingly coming into focus with an

acknowledgment that regulation needs to be a facilitator of, not an

impediment to, technological development.

The tone of the discussion is changing. The Smart Systems and

Flexibility Plan (July 2017), a joint initiative by Ofgem and BEIS, led

to multiple recommendations being progressed across a range of

detailed but important matters such as storage licensing and industry

charging. National Grid is reforming balancing services through its

System Needs and Product Strategy (SNaPs), and there are radical

moves to make Electricity System Operation more independent.

Distribution Network Operators (DNOs) similarly are engaging far

more in innovation in response to legitimate questions about their

pace in fostering technological innovation. Ofgem has also started

a debate on whether the current supply market arrangements,

including the continuation of the supplier hub model, are appropriate

as the scale of capability of new technology and new actors to deliver

better outcomes to consumers becomes apparent.

The challenge the GB market faces remains how best to deliver

enduring low-carbon, secure and affordable supplies for all

consumers. That challenge is shared across all developed electricity

markets. Opportunities abound but the sector and its players will

continue to face new challenges as innovation continues and the

speed of technological change increases. The transition in energy

markets raises the question of what we are transitioning to. There

are many key options and choices presently being debated, with

technology playing a key role. The challenge for all engaged in

the sector is to understand both current developments and future

opportunities, and engage fully in the debate.


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Cornwall Insight / Gowling WLG whitepaper \ Generation

5

GENERATION

The mix of technologies generating power across the GB electricity system has evolved in response to market and policy considerations, innovation and availability of capital. Improved turbine technology, abundant fuel, and interest from foreign capital in British generation enabled by a change in law allowed for the ‘dashes for gas’ in the 1990s, where combined cycle gas turbine (CCGT) capacity went from zero to 19.3GW by the millennium.

Market deregulation gave way towards the back-end of the 1990s

to the increasing policy imperative to decarbonise the sector –

underpinned by the introduction of incentive mechanisms in the form

of the Renewables Obligation (RO) in 2002, the small-scale Feed-in

Tariff (ssFiT) in 2010 and finally the Contract for Difference (CfD)

regime from 2013. These mechanisms led to a rapid deployment

of renewables. They spawned a booming investment market, both

primary investment in Greenfield sites but also increasingly a liquid

and sophisticated secondary market. In recent years, this secondary

market, populated for the most part by infrastructure and pension

funds, has driven consolidation of ownership and a new focus on

utilising innovative asset management techniques to drive enhanced

yields, particularly as certain income streams have been diminished

or removed, such as Levy Exemption Certificates (LECs) in 2015 and

latterly embedded benefits.

Figure 1: Total installed renewable capacity 2010–2017

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Cumulative CCGT closed Cumulative nuclear closed Cumulative coal closed Net new Interconnector capacity

Figure 1: Total installed renewable capacity 2010-2017

Figure 3: cumulative plant retirement forecast, net of interconnector additions

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Figure 3: cumulative plant retirement forecast, net of interconnector additionsSource: BEIS


6

The Offshore Wind Programme Board, which brings together

industry and government to find and implement solutions to barriers

which may impede the viability and deliverability of offshore wind,

concluded in its Cost Reduction Monitoring Framework 2016 report

that technology developments have made the largest contribution to

cost reduction. Cost reductions are being seen globally, with tenders

for offshore wind in North West Europe delivering prices at or below

the GB levels. The discussion is now turning to whether offshore wind

could be genuinely subsidy-free and if so by when.

It is not just offshore wind where costs have declined dramatically.

Solar and onshore wind has followed a similar trajectory. The

government’s own figures on LCOE from 2016, already being

overtaken by cost evidence on the ground, show the rapid change

in expectations on costs wrought by a combination of technological

improvement and increasing comfort amongst investors’

overproduction risk:

While landfill gas led the charge in the 1990s, that technology was

superseded by wind power, both onshore and offshore, and from

2010 solar PV. Biomass conversion has also played an important role,

as less numerous but nonetheless large coal fired power stations like

Drax and Lynemouth have converted to burning biomass in response

to incentives provided by the decarbonisation agenda.

Offshore wind most obviously demonstrates the way technology

development has driven reduced costs of deployment. In 2012, the

Government tasked the offshore wind sector to conduct a review on how

to bring down costs and set a target to bring the Levelised Cost of Energy

(LCOE) for offshore wind down by a third to £100/MWh by 2020.

By 2016 the sector reported that the target had been met and in

the second CfD allocation round for less established renewable

technologies in the summer of 2017, 860MW of offshore wind

projects were awarded contracts for delivery in 2021–22 at £74.75/

MWh and a further 2,336MW for delivery in 2022–23 at £57.50/

MWh (the latter price is cheaper than the LCOE of new Combined

Cycle Gas Turbines (CCGTs)).

Figure 2: Change in Levelised Cost Estimates for Projects Commissioning in 2016, 2020 and 2030 (£/MWh)

Source: BEIS Electricity Generation Costs 2016

Commissioning 2016 2020 2030

DECC 2013

BEIS 2016 report

DECC 2013

BEIS 2016 report

DECC 2013

BEIS 2016 report

Large scale solar PV 108 80 92 67 69 60

Onshore wind>5MW UK 88 64 85 63 82 60

Offshore Wind Round 3 155 109 136 106 120 96


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The deployment of high levels of low-carbon generation has led to

new operating records. On 21 April 2017, the GB sector experienced

the first 24-hour period without any coal generation since the

Industrial Revolution; over half of electricity generated during the

summer of 2017 was from low-carbon sources; a quarter of all

supply was from solar on 26 May 2017, and the highest electricity

production from all wind generation at any one moment (12.4 GW)

was on 6 December 2017.

With this success come additional challenges, particularly for system

operation. As the system becomes increasingly characterised by

intermittent generation, there is greater need for ‘flexibility’ to

manage real-time supply and demand. The challenge is caused

not only by the upswing in large-scale renewables connected at

the transmission network, but also by the very rapid increase in

renewables deployed at the distribution network.

As older and large-scale synchronous plant leaves the system, there

are emerging issues with system frequency and inertia, creating a

need for new providers to fill the “flexibility gap”, and the opportunity

to access revenue.

Assets above certain de minimis limits that can alternate between

services and markets have the potential to “stack” revenues. They can

access peak wholesale prices, balancing services contract revenues

or operate directly in the Balancing Mechanism. If they are not

receiving other sources of low-carbon support, and are successful

in auctions, they can also earn capacity payments. Depending on

their connection voltage, plant can also accrue “embedded benefits”,

although some of these have been significantly reduced by recent

regulatory decisions and others are subject to on-going review as part

of Ofgem’s Targeted Charing Review.

These conditions have allowed the role of the aggregator of flexibility

sources to expand and flourish, with real growth in, for example,

the aggregation of small, reciprocating diesel, biodiesel and gas

engines and with an increasing focus on flexibility from Demand Side

Response and lithium-ion storage batteries.

Frequency and Inertia

National Grid, as the GB System Operator, has a statutory

obligation to ensure system frequency is kept at 50Hz,

± 0.5Hz and an operational target to keep it within

±0.2Hz. However, the frequency of the energy system is

a constantly changing variable, which is determined and

controlled by the balance between the demand on the

system and available generation. If demand is greater than

generation, then frequency falls, whereas when generation

is greater than demand, frequency rises.

System inertia is characterised by the amount of energy

stored in rotating masses (i.e. turbines) directly coupled to

the network. The shift from “synchronous” technologies

(e.g. coal, gas and nuclear), to “asynchronous” (e.g. wind or

solar) has already lead to a reduction in system inertia, and

this trend is set to continue as greater renewable capacity is

added to the system.

As inertia falls, the rate of change of frequency increases,

requiring the System Operator to procure services from a

widening range of providers that have the capability to alter

output over very short timescales.


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OUTLOOK

Significant new investment will continue to be required to replace

ageing technology. Environmental legislation will see coal-fired power

stations closing by 2025. With higher operating and carbon costs, and

lack of success in the most recent Capacity Market auctions, it is likely

that much of the remaining capacity will leave the system before that

date. The majority of the existing nuclear fleet is also expected to be

phased out during the 2020s, and some of the original generation

CCGTs will need significant investment to remain viable.

Views on what replacement capacity will come forward and when,

and how much the system really needs, change for many interlinking

reasons. Projections of future power demand are uncertain, both

in terms of the primary factor of peak demand, and in light of how

demand patterns may change with the electrification of heat and

transport and the leveraging of smarter technology behind the

customer’s meter. Consumption patterns are also changing in line

with consumer behaviour as costs of energy and its delivery increase.

Wholesale price forecasts are becoming complicated by the increase

of zero/ low marginal assets such as renewables, which has seen

significant volatility in prices across all markets with sizeable fractions

of renewable capacity.

Except for the next CfD auctions to spend £557mn of budget (the

next one is planned for Spring 2019), the government has signalled

no additional subsidy for generation beyond that which is already

committed. There is uncertainty about the timing of delivery of

Hinkley Point C and other possible new nuclear sites. GB has already

committed to 7.7GWs of new electricity interconnection projects

to be delivered in the early 2020’s, with the related uncertainty

about the direction and volume of flows. Capacity market auctions

are delivering some new build capacity, but through less visible

decentralised gas, battery storage and DSR, and not the new large-

scale, transmission-connected CCGTs the government had hoped to

see. Regulatory and policy risk remains a real concern in the Capacity

Market, as evidenced by continuous amendments to scheme

requirements (and related matters such as emissions controls), which

appear to seek to alter the balance of incentives for different kinds

Revenue stacking

Multiple income streams can be accessed by a single

asset, where it has the technical and commercial flexibility

to operate across the compatible wholesale, balancing

services, and capacity markets. Operators will often

outsource the route to market activity to an aggregator

or other specialist that has the knowhow to compete for

balancing services contracts, possibly operate directly in the

Balancing Mechanism, trade in the wholesale market, ‘spill’

uncontracted volumes into the market to gain the system

imbalance price and take part in annual Capacity Market

auctions.

The asset will then be run to optimise revenue across

the various income streams, recognising that some may

place an obligation on the generator to be available during

a prescribed period (e.g. balancing contracts), and that

forecasting short-term wholesale market and wider system

dynamics is necessary.

This revenue stacking is becoming increasingly important

in creating the business case for new projects, providing

as it can greater diversity in the potential income streams

and therefore sources of return on investment for finance

providers.


9

of participating plants. Furthermore, the regulatory framework for

accessing and using networks is under review, creating uncertainty for

cost and revenues projections.

Despite all of these uncertainties, developers and investors continue

to innovate to find ways of delivering new and viable projects, with

technology playing an increasing role. Stacking multiple revenue

streams requires more than deploying an efficient generation asset.

It also requires robust communication equipment to enable the

operator to communicate with multiple parties, be it the trading

partner in the wholesale market or National Grid where providing

balancing services or participating in the Balancing Mechanism.

Data analytics is key in both ensuring that a plant can deliver to

meet its multiple contractual obligations, and increasingly to give

operators an insight into the changing market dynamics and how to

best optimise available revenue opportunities. The opportunities will

increase as the entire system becomes more actively managed and

access to quality information will become a critical component in

making the best of the available returns from flexible assets.

With the removal of subsidies, renewable developers are now looking

at the viability of subsidy-free projects. Currently any such project

is likely to need to be underpinned by a long-term Power Purchase

Agreement (PPA) with a utility, trader or large corporate with good


Source: Cornwall Insight analysis

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10

or storage on-site in response to changes in system needs. The model

brings together two of the trends witnessed in the sector in recent

years: the maturation of the renewables development model with the

growth in standalone portfolios of utility-scale flexibility.

The model is exemplified by Anesco’s well publicised co-location of

10MWs of ground mounted PV solar with 6MWs of battery storage

project at Clayhill in Northamptonshire. The development is subsidy-

free, partly helped by the sharing of grid costs with an adjacent

subsidised solar project and rapid falls in panel and battery costs.

However, battery revenue streams (for example through the Capacity

Market and the provision of frequency response services) will be

important to a sustainable model for this and other co-location

projects unless and until battery costs fall further. Again technology

plays a key part. Beyond the siting of two forms of load under a single

connection, at a single site, the project uses a new string inverter

system for the European market. The system is claimed to both

financial standing, and typically featuring a floor or fixed price

element to mitigate downside risk. Greenfield development models

for sites with individual technologies on a subsidy-free basis currently

appear to be viable only for the more mature technologies in

optimum development locations, with equity often being the funding

source. As technology costs continue to fall, the range of projects

and investment structures at play in the subsidy-free world have the

potential to increase significantly.

Developers of renewable energy projects are beginning to consider

other modes of build out; for example ‘hybrid’ power plants, that

include flexible non-renewable sources of generation and storage at

the same site in a single integrated generation unit, or which create

microgrids of locally connected sources of load. Hybrid models can

either be grid connected, or connected to private wires. Developers

benefit from the project’s ability to source value across fluctuating

levels of demand and prices, triggering different forms of generation

Figure 4: day-ahead price volatility 2013 to 2018

Source: N2EX

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Two Degrees Slow Progression Steady State Consumer Power History

Figure 5: Residential Heat Pump Peak Electricity Demand

Figure 7: Timeline of EV commercial model development Nov 2016 to Dec 2017


Nov16 Mar17 Jun17 Sep17 Oct17 Nov17May17 Dec17

VattenfalllaunchedinChargepublicnetworkinNorthernEurope

EngieacquiredEV-Box

EngieentersGBsupplymarket

VattenfallacquirediSupplyEnergyandenteredtheGB

market

OvoEnergyacquiredChargedEVandIndra

RenewableTechnologies.PartneredwithChargemaster Ovopartneredwith

Nissan

ShellacquiredNewMotion

EcotricityexpandedElectricHighway

OvopartneredwithUbitricity

ShellpartneredwithIONITY

E.ONUKlaunchedE.ONDrive

IbedrolatrialsEVchargingsystem

ShellacquiredFirstUtility

GoodEnergypartneredwithNewMotion


11

component projects, forecasting and dispatching units in response to

changing market conditions.

The component units can remain independent in their operation

and ownership, but individual owners can realise the diversity value

created by the ability of the VPP to access wholesale, balancing

service and embedded benefit revenue streams across different

time horizons. System operators also benefit from the intelligent

aggregation and control of individual units responding directly to the

incentives and signals being sent by markets.

But, the investment case for a flexible generator, battery, or VPP

participant is very different to a subsidised renewable project. There

is no single long-term and regulatory backed source of value capable

of supporting large debt components in the capital structure for

many of these projects. The appetite of traditional project finance

debt providers or risk averse equity such as pension funds is therefore

currently limited. Significant levels of “risk” equity are typically

required as part of any funding package.

improve power yield and be more reliable. According to Anesco, the

impact has been to lower costs and make the combination of solar

and storage attractive at the Clayhill location.

The Clayhill example shows that the ancillary technologies that

wrap around hybrid systems play an important role in viability – for

example, sophisticated control and optimisation systems will turn off

and on different sources of flexibility at the hybrid site, interacting

with wholesale and balancing service markets to maximise revenue

opportunities.

In other markets such as Germany and the US, the hybrid model

has already seen broader combinations of assets including through

the use of Virtual Power Plants (VPPs). Like hybrid power projects,

VPPS combine different forms of storage, demand response and

generation but not in a physical configuration. Instead, VPPs create

virtual networks of separately located units, dispatched through a

central control point. The control point is remote, transferring data to

The “hybrid” power plant model

www.cornwall-insight.com

1

Wind Solar Thermal

Load/ demand Storage Control centre

Diesel


2

Within a blockchain network it could be possible to achieve current operations (such as consumer billing, optimisation of generation, network management) via an open access distributed online ledger and transaction system. Proponents believe the approach could usher in significant innovation, cost reduction, and efficiency and unlock DSR and other flexibility solutions. Unlike today’s centralised trading and settlement activity run by a small number of industry specialists, rules and contracting would be decentralised and remove human bias from transaction management and record-keeping processes. The technology means that data is incorruptible

Conventional

Blockchain

Case studyStatkraft’s Virtual Power Plant

Statkraft operates a virtual power plant in Germany, which at over 5GW has a larger capacity than the largest nuclear or coal plants in the country.

It is made up of more than 1,000 small-scale producers, comprising 940 wind farms, almost 100 solar plants, 12 biomass sites and some hydropower generation assets. The distribution of these assets, and the resulting differences in weather conditions, mean that there is always some wind or solar plants generating.

Janosch Abegg, Head of Market Access and Integration of Renewables at Statkraft, explained: “By using the virtual power plant, Statkraft knows how much power each facility generates at any given time. As a result, we can deliver both flexible and demand-based capacity from renewable resources.”

Source: Statkraft


12

Additionally, particularly in the current environment, many see

regulatory and policy risk as greater than was associated with

schemes such as the RO, small scale FiT and CfD. The government

is required by statute to undertake a five-year review in 2018–19

of the Electricity Market Reform programme, which introduced

both CfDs and the Capacity Market. That review presents a real

opportunity to modify programmes based on the first five years’

experience. The outcome of the review will provide a real signpost

as to the future policy direction of travel. National Grid is nearing

the end of its ‘Power Responsive’ initiative that aims to simplify and

widen participation in all forms of demand-side flexibility. Linked

to this is its System Operator System Needs and Product Strategy

that looks to rationalise, standardise, and improve how it contracts

for balancing services contracts from non-conventional and smaller

providers. Both will be important in identifying system requirements,

how they are procured and the role flexible assets of all types can

play in delivering them going forward.

Additionally, the structure of network charging is under review in

light of real concerns that the current structure based on system

usage is likely to lead to increasing unfairness as more off-grid

solutions and technological advances change the way and extent

to which networks are used. The approach to network charging is a

key component when considering the financial models underpinning

particular assets. The regime has been settled for many years; with

the conversation now moving towards possible alternative models

based on capacity, connection voltage or location; the status quo is

unlikely to remain.

The outcome of these programmes will be very important to the

opportunities available to those looking to develop flexible assets,

hybrid solutions or subsidy-free renewables. It may be positive for

some and encourage the development of new solutions – asset and

business model driven – to maximise the opportunity. But there is no

doubt that the current level of uncertainty created by the continuum

of change across a variety of different revenue and cost sources has

the real potential to deter or delay the investment in and deployment

of new solutions which could add real value to the sector.


13


14

Cornwall Insight / Gowling WLG whitepaper \ Networks

15

NETWORKS

The proliferation of proposals for the deployment of small-scale renewable generation assets, often at the periphery of the network, deep in the lower voltage distribution network, or in locations where wholly new infrastructure is needed, initially created grid queues under the ‘invest and then connect’ model adopted by network operators. That threatened our ability to achieve national and European renewables targets. As a result, the decision was made in May 2009 to introduce a ‘connect and manage’ approach to granting connections to the transmission system. This approach significantly shortened connection offer times, by an average of five years.

The necessary investment in new network capacity is nearing

completion with the Western Link, connecting Hunterston to Deeside

via a 2.2GW subsea HVDC link, expected to be fully operational by

the end of 2018. The 2GW Eastern subsea HVDC link is still in the

planning phase but could be fully operational by 2021. This example,

whereby certain key network infrastructure has taken so long to catch

up with the growth in renewable power, highlights the difficulty of

networks to keep pace with changes in volume, efficiency and scale

occurring in technologies that connect to them.

These pressures to keep up are not dissipating, and new technology

stimulated by policy imperatives are only set to intensify the need for

approach to network management to adapt and evolve quicker than

they have ever done.

There is much greater complexity emerging at the distribution

network level. The electrification of heat to meet the 4th (2023–27)

and 5th (2028–32) Carbon Budgets will necessitate widespread

use of heat pumps. Although the transmission system will not be

immune, the impact of significant heat point deployment is expected

to be felt most keenly on the low-voltage distribution network. The

added burden on electricity networks of winter heat demand at a

domestic level is likely be profound given that heat demand exceeds

electricity demand by about three times across a typical year. Local

voltage and capacity issues are likely to need to be addressed through

reinforcement unless alternative ways to manage supply and demand

on the networks can be found.

The roll-out of Electric Vehicles (EVs) presents a similar challenge.

National Grid, analysis in the government’s Clean Growth Strategy

and other national and international market studies have shown that

significant growth in EVs could be accommodated nationally without

the need for substantial system reinforcement. But they acknowledge

that that would only be feasible if smart methods of charging EVs

are developed. However, much of the charging demand is likely

to be at domestic level where the network infrastructure is not

sufficiently equipped to simultaneously deal with existing demand

levels and additional demand driven by substantial and lengthy EV

charging requirements.

Forecourt charging may be part of the solution. But even here

major charging infrastructure deployment will require significant

reinforcement to the distribution network. Creative ways to minimise

the costs of that reinforcement by incentivising changes in behaviour

and consumption will come into sharp focus.

The continued rise in ‘behind the meter’ or private wire generation

to either avoid expensive and lengthy connections to the licensed

network and/ or reduce users’ overall electricity costs also will create

further challenges, both for network design and the ability to recover

sunk costs through use of system charges (which are currently not

typically payable by on-site generation where there is no export).

It is possible that a charging mechanism based other than on net

metered demand, reflecting a capacity-based approach – one of the

options currently being considered in the Ofgem Targeted Charging

Review (TCR) on network charges – will lessen the commercial

incentive for such arrangements. But it is not inconceivable that such

an approach could result in a future scenario where some significant

demand users may favour investing in storage (static or in EVs)

coupled with onsite generation, disconnecting from the licensed

network completely and accepting the risk of a short-term loss

of supply.


16

The range of Electric Vehicle impacts on demand

Source: National Grid

Figure 6: Number of GB suppliers and independent market share 2010-2017

What is the “Supplier hub”?


15

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National Grid projected in 2017 that, under a high uptake scenario, EVs would add over 45TWh/year of electrical demand to the GB system. Without smart charging, this would add 18GW to existing peak demand.


Source: National Grid

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17

Finally, mooted and planned changes to retail market arrangements,

addressed later in this report, also have the potential to

fundamentally see users change from being largely passive consumers

of power to an integral part of the overall system, using technology

to both optimise assets and use them to offer energy and network

management services.

This backdrop of rapid change has seen the political and regulatory

focus on network costs and their allocation between network users

heighten, with a very different policy and regulatory environment

beginning to take shape. Continuing concerns about the cost of

electricity to consumers is also resulting in increasing scrutiny of the

level of regulated returns being made by network companies under

the existing price controls (RIIO ED1) running from 2015–2023,

with the question of what is an appropriate approach to regulating

network charges high up Ofgem’s agenda. Regulated companies have

been very good at developing innovative schemes and benefiting

from the arrangements to encourage innovation under existing

price controls, but whether the balance between rewarding them for

innovation and the impact on consumer bills is the right one is now

generating much debate. Cornwall Insight’s analysis shows network

costs rising in real terms in domestic consumer bills in the medium

to long term, a development that will no doubt be a key area of focus

in the next round of price controls. A recent report by the Energy and

Climate Intelligence Unit3 (ECIU) has intensified the focus on network

operators’ contribution to bill costs, by identifying an average DNO

profit of 30.4% during 2016.

3 http://eciu.net/

Stuart Young

Head of Automotive, Partner

Gowling WLG

A marked increase in the production of electric vehicles (EVs) has been triggered by an ambitious government target to completely ban the sale of new cars and vans powered solely by petrol or diesel by 2040, and for EVs to equate to 9% of overall production by 2020. This is helping to direct collaboration and initiative within the energy industry as well as stimulating extensive innovation in the automotive industry. The automotive sector is becoming increasingly aware, however, that the commercial market for EVs will be seriously hampered without solutions to range and recharging that will bring EVs closer to the convenience and cost of petrol and diesel vehicles. Part of that solution will be technological but the need for a recharging infrastructure is unlikely to disappear. The big question is who is going to pay for that infrastructure? The vertical integration (well-to-pump) that was available to the nascent oil business is not available for electricity. The need for collaboration to find a solution will shortly become acute.


18

NETWORK INNOVATION

Network innovations targeted at reducing both operating and capital

costs are therefore coming into sharper focus. Opportunities range

from specific technological measures relating to individual pieces of

infrastructure, to harnessing technology to completely re-design how

those who connect to networks relate to one another.

The use of facilitative technology that integrates those who connect

to the network intelligently – both demand and generation – has

the potential to transform the future of networks, and reduce costs

invested in network infrastructure. The new world could see networks

and network operators acting less as linear conduits between sources

of generation and sources of demand, and more as platforms for real-

time integration of the two, with the potential to reduce network

stress, costs and the risk of load loss.

Blockchain is often referenced as one potential enabler of this change:

a distributed ledger that records transactions between decentralised

parties. The transactions automatically reference each other, forming

an unbroken chain and avoiding the need for a central clearing house

to settle transactions between buyers and sellers. Blockchain is now

commonly used in the trading of crypto-currencies such as Bitcoin.

In the energy market, exponents of blockchain describe how it

could allow for the development of an integrated grid, where data

transfer between directly connected producers and consumers

allows for smarter real-time network management. The prospect is

undoubtedly attractive. However, both network management and

the energy trading that can help with active network management

is complex, and typically does not involve the settlement of a

single transaction. Under current market design numerous players

sit between buyers and sellers – suppliers, network operators, and

existing settlement arrangements – and unlike cryptocurrencies the

underlying commodity is sometimes physical. Further data relating

to demand and production interacts with other cost-collection

elements of the system such as imbalance pricing, network charging

and levy collection. There would need to be judgements made about

the purpose of each intermediation, and whether it is desirable or

David E BrennanPartner and Co-Chair of TechGowling WLG

The energy sector has traditionally been slow to respond and take advantage of emerging technologies, but the introduction of blockchain technologies into the way energy is traded could fundamentally change this. The triggering of direct and smarter real-time network management between energy producer and consumer has the potential to be facilitated through a decentralised transactional digital ledger, removing the need for an agent or clearing house.

While there are innovative projects underway in this area, there is still work to do before the process can be successfully rolled out. The technical issues that need to be overcome to do this require a high level of cooperation between multiple sectors and services. Furthermore, the regulatory framework that directs the process is still to be properly established, meaning that the collaboration achieved to date must continue in earnest if blockchain is to truly disrupt and transform the sector.


19

efficient to disintermediate across each area of the current structure,

and in each case, given transaction costs vary, whether material

levels of cost could be removed. Rules based automation in network

balancing and optimisation based on blockchain enabled data flows

are part of the potential applications being explored in this context.

Evidence on where and how much blockchain could beneficially

impact on the energy system is still limited, although developing

globally. The US Department of Energy began exploring the

application of blockchain to re-design of electricity grids in 2017. In

Australia, Power Ledger has developed a peer-to-peer blockchain-

enabled energy trading model that allows people to sell their

rooftop solar power directly to other households at a higher price

than they would get by selling to a utility company and therefore

maximising income, asset viability, and potentially reducing network

capacity constraints.

In Great Britain, in September 2017, Electron, a private company,

announced that it has been awarded substantial funding from the

government’s Energy Entrepreneurs Fund to examine how blockchain

might improve the balancing of the electricity network. The

application was supported by National Grid and Siemens on market

design and on implementation respectively. The principle is that

blockchain technology will allow multiple parties to co-ordinate and

share the value of a single consumer’s action, maximising liquidity in

the flexibility market, and enabling lower balancing costs through the

participation of a greater number of providers located at many more

points across voltage levels of the network.

The potential for blockchain technology to fundamentally change

the current network operation models is an exciting one, but it

appears to be widely acknowledged by policy makers, regulators

and industry that if any potential is to be maximised, current

regulatory and institutional frameworks will need significant

work. Some progress is being made. In September 2017 Ofgem’s

Innovation Link held a roundtable discussion on the application of

blockchain in the UK energy sector. The discussion covered broad

ground such as regulatory responsibility and the challenges in

any regulatory model given the cross-over into areas such as data

“Blockchain” and energy


1

Wind Solar Thermal

Load/ demand Storage Control centre

Diesel


2

Within a blockchain network it could be possible to achieve current operations (such as consumer billing, optimisation of generation, network management) via an open access distributed online ledger and transaction system. Proponents believe the approach could usher in significant innovation, cost reduction, and efficiency and unlock DSR and other flexibility solutions. Unlike today’s centralised trading and settlement activity run by a small number of industry specialists, rules and contracting would be decentralised and remove human bias from transaction management and record-keeping processes. The technology means that data is incorruptible

Conventional

Blockchain

Within a blockchain network it could be possible to achieve current operations (such as consumer billing, optimisation of generation, network management) via an open access distributed online ledger and transaction system.

Proponents believe the approach could usher in significant innovation, cost reduction, and efficiency and unlock DSR and other flexibility solutions.

Unlike today’s centralised trading and settlement activity run by a small number of industry specialists, rules and contracting would be decentralised and remove human bias from transaction management and record-keeping processes. The technology means that data is incorruptible.


20

system operators. To date, much of that innovation has been

supported through funding via the Low-Carbon Network Fund

(LCNF) and Network Innovation Competition (NIC).

There are linkages to the RIIO process, and how the time horizons

of this process allow for incentives to be adapted, quickly enough to

drive the change in DNO activity. The concern is that if the full scope

of change in technology or innovation, or the incentives established

to explore these, is not accounted for in long-term price controls

for network operators, then there is a danger of inappropriate price

settlements being established. Ofgem may then need to account for

how the system has changed through mid-period reviews of network

price controls, which would be a messy solution.

Although it is early days yet, Ofgem has already indicated that it

will be looking to set stronger incentives for innovation in the price

control arrangements it sets for electricity distribution companies

from 2023 (under RIIO-ED2). It has also publicly stated that it wants

to see more collaboration between network companies in their

approach to solving systemic problems so that smart solutions can

be rolled out across all networks, with current concerns that the

dissemination of benefits from innovation between DNOs is unclear,

security, privacy and cyber-security. It also explored the adoption

of blockchain markets in other industries and jurisdictions. Ofgem

is due to produce a more detailed report in 2018 but it is clear that

the thinking on the appropriate regulatory approach to facilitate this

type of technological development is in its early stages and remains

a long way behind the development of the technology it should aim

to facilitate.

The proposed move from DNOs to DSOs is also an important

complementary move if technological change is to be facilitated at

distribution level and the benefits are to be harnessed. The objective

of this transition is the creation of regional actors which adopt

measures that look at cost-efficient alternatives to reinforcement

investment and seek out solutions for harvesting local flexibility and

balancing to manage the local system dynamically. This is different

to the traditional DNO model that is based on management of the

infrastructure necessary for connection of demand or load to a local

network, and managing the interface between that network and the

transmission system.

Against this backdrop DNOs are already beginning to innovate to

deliver solutions that are more aligned with the model of regional

Network innovation, sandboxes, and funding

Ofgem created the Low Carbon Networks Fund (LCNF) as part of

the previous electricity distribution price control (2010 to 2015)

that permitted up to £500mn to support DNO-sponsored projects to

trial operating and commercial arrangements. The aim of the projects

was to assist all DNOs in understanding how they can provide

security of supply at value for money as Britain moves towards a

low carbon economy.

Funding was split into two tiers. The First Tier allowed DNOs to

recover a proportion of expenditure incurred on small-scale projects;

the Second Tier was an annual competition for an allocation of up to

£64mn to help fund a small number of flagship projects.

With the introduction of RIIO the LCNF was expanded and

became the Network Innovation Competition (NIC), with annual

competitions for network companies to compete for funding for the

development and demonstration of new technologies, operating

and commercial arrangements. Up to £70mn per annum is available

through the Electricity NIC.


21

and value for money assessments are difficult to make. There are also

concerns that access to innovation funding is presently licensee-led,

and therefore the drive for innovation depends on licensee appetite

and ability to access funds. There are no clear and obvious incentives

outside of the funding process for DNOs to invest strategically

without user commitments being in place to support that investment

– another issue for potential consideration by the regulator in the

RIIO-ED2 process.

Notwithstanding the challenges, innovation is happening, even if

the arrangements for the sharing of benefits and wider adoption

of learning are far from perfect. For example, Northern Powergrid

has engaged in a smart-grid programme to install new digital

communications at substations, introduce new dynamic voltage

control systems, replace and upgrade substation controls, and create

new warehouses to process data from both substations and domestic

smart meters. This is being designed to create a base-level of data

and communications flows on which further system optimisation can

be developed. Interestingly this is being funded not from innovation

funding, but from the DNO’s business as usual spending allowance

under the RIIO ED-1 price settlement.

Open Utility’s Piclo trading platform is to be used by another

DNO, UK Power Networks (UKPN), to develop and trial an online

marketplace for local flexibility. Open Utility has previously secured

£400,000 funding through BEIS Energy Entrepreneurs Fund to

develop its local energy trading platform into a new flexibility

marketplace. UKPN intends to use the new platform to help open

new markets for flexibility providers by making it easier for them to

sell their services and help UKPN manage peak demand. The use of

the platform aims to digitise the procurement process for flexibility,

streamline the bidding process for service providers and allow

UKPN to better match service providers to network needs.

Despite some intriguing headline projects, the sector is currently at

a very early stage in utilising new technology to optimise networks,

reduce costs and benefit consumers with initiatives supported in the

main by innovation funding. Projects are mostly at an early stage

and have not yet translated into widespread adoption of common

approaches at the DNO level. This must happen if there is to be

widespread adoption and identification of best practice, and the

transition to DSO operation is to become a reality.

More recently, Ofgem has introduced its Innovation Link, which it

describes as a ‘one stop shop’ offering support on energy regulation

to businesses looking to introduce innovative or significantly

different propositions to the sector. Where an applicant’s innovative

proposition is accepted by Ofgem it is permitted to operate within a

‘regulatory sandbox’ – effectively allowing it to undertake activities

that would not be possible under the existing regulatory framework

and to trial new propositions which would otherwise be precluded.

BEIS administers the Energy Entrepreneurs Fund. This competitive

funding scheme, run over a series of phases, aims to provide

support for the development and demonstration of state of the

art technologies, products and processes in the areas of energy

efficiency, power generation, and heat and electricity storage.

For the current phase (Phase 6), a total of £10mn is available.

The scheme particularly aims to assist small and medium-sized

enterprises, including start-ups, and those companies that are

selected will receive additional funding for incubation support.


22

It is unclear if we will ever really move to a solution of regional

network operators acting as a platform for connected generation

and demand and facilitating trading opportunities at a local level,

or how technologies like blockchain will ultimately shape that

journey. What is beyond doubt however is that the scope and

impact of technological innovation in networks could be profound

if fully harnessed.

WPD and the DNO to DSO transition

Western Power Distribution (WPD) set out its DSO

strategy in December 2017. It states that it will deploy

DSO competences by taking a top-down approach,

commencing with the 132kV, 66kV and 33kV networks as

the initial priority areas, with the remainder of the network

to be upgraded as customer need requires. It prefers this

approach as the upper voltage tiers of the network have

higher utilisation rates and are therefore most disrupted by

the addition of new distributed energy resources.

WPD will also make use of smart meter data and extra

network sensors to enable wider flexibility for the use

of import/export constraining as an alternative to

conventional solutions and only reinforcing the networks

when these solutions are necessary. Active Network

Management (ANM) will be rolled out across a number of

zones through to full availability across its entire network

by 2021.

Improved forecasting should allow WPD to provide real-

time and predicted constraint levels for distributed energy

resources. In turn this will determine the levels of constraint

to be used when dispatching flexibility services and ensure

the network is managed to maximise capacity.


23


24

Cornwall Insight / Gowling WLG whitepaper \ Retail markets and consumption

25

The energy supply sector has witnessed some tumultuous times since retail competition was fully introduced in 1999. Prices for consumers fell until the middle of the first decade of this century, when the trend reversed as GB became a net importer of gas for the first time at a period when international commodity markets were particularly volatile. The generally upward pressure on consumer bills in recent years has been increasingly driven by rising policy and network costs. In turn rising consumer costs have meant that the sector has rarely been out of the political spotlight – that position is unlikely to change, particularly with costs anticipated to increase further.

The energy supply market is now an ideological battle-ground, with

debate focusing around issues of fairness and social justice. This

focus intensified from 2014 onwards with Ofgem’s referral of the GB

energy market to the Competition and Markets Authority (CMA).

The outcome of the CMA’s investigation is currently manifesting

itself through Ofgem’s extension of price caps from pre-payment

customers introduced in April 2017 across a widening base of

vulnerable customers. Although the CMA rejected a wider price cap,

the government has decided to introduce new legislation, introduced

to Parliament on 26 February 2018, to require Ofgem to set an

absolute cap on standard variable and default tariffs ahead of next

winter for the 11 million households in GB who currently buy their

energy on this basis and who are not protected by existing price caps.

There has been a marked narrowing of differentiation across the main

political parties on their views of the role of deregulated markets

in energy, with a new consensus emerging that interventions to

cap prices or bills are necessary, at least until the benefits of smart

meters and other innovations become widespread. We have also

seen a consequential increasing interventionist approach from

Ofgem and government over recent years, which is manifesting

RETAIL MARKETS AND CONSUMPTION

itself not only in price regulation, but in driving through changes

in technology in the domestic market that have the potential to

unlock considerable benefits for consumers in the medium to long

term. The combination of the mandated smart meter roll-out and

the progress towards market-wide, half-hourly settlement, which

is now targeted for 2020, could be transformational. But they also

introduce opportunities for greater data analytics, opportunities for

more sophisticated pricing (recognising valid social concerns related

to those that cannot respond to time of use price signals), and the

creation of local markets to optimally manage local generation and

network characteristics.

Smart meters and improved data

All consumption meters should be ‘smart’ by the end of

2020. GBs largest businesses (>100kW demand) have been

metered on a half-hourly (HH) basis since market opening,

and as of April 2017 a further 170,000 meters (around 15%

of national demand) have been HH metered and settled via

Automated Meter Reading (AMR) equipment. Smart meters

are planned to be rolled-out to all remaining customers

(households and smaller businesses) and the Market-wide

Half-Hourly Settlement Significant Code Review seeks to

ensure consumption data is used for settlement purposes

around the same time the asset deployment is complete.

Time of Use (ToU) tariffs are often mooted as a key benefit

of the technology, where users are directly exposed to a

price signal that corresponds to market conditions and

network stresses. How attractive these products are

remains to be seen, but where they can be dovetailed

with consumer generation or storage (including EVs) at an

individual site or collectively across a proximate locale they

may be more effective.


26

At the larger end of the supply market, SSE and Innogy Npower have

agreed in principle to merge their domestic supply functions into a

single standalone retail entity, possibly by early 2019. Shell recently

acquired First Utility, and Vattenfall purchased the smaller domestic

supplier isupply earlier in 2017. In the business sector, Drax added

Opus Energy supply to its portfolio alongside Haven Power.

Of course, tougher market conditions could also result in greater

innovation. Some acquisitions may be strategic – a route to market

for novel technology driven approaches to sell services in addition to

energy. With profit margins for energy supply being squeezed, many

suppliers are looking to business models encompassing differentiated

supply offerings to grow revenue per customer. Opportunities arising

from the current and forecast growth in electric vehicles are proving

particularly interesting, with a number of suppliers already seeking

early-mover advantage.

MARKET RESPONSE

Contrary to the prevailing political narrative, retail market dynamics

have been steadily improving. Today, 64 companies supply energy

to households and over 20 to businesses; this is in stark difference to

the number at the turn of this decade where 99% of households were

served by the Big Six energy companies. Customer switching levels

are at a 10-year high at around 450,000 a month during 2017. There

is also considerable evidence of tariff innovation now that regulatory

limits on the number of core tariffs have been removed.

But we may well now be moving from an era of participant

proliferation to one of consolidation. It increasingly makes sense in

today’s setting to have scale both to cope with increased wholesale

price and system volatility and potentially to strip out costs as

sources of historic profitability, such as variable tariffs, are phased

or forced out of the market.

Figure 6: Number of GB suppliers and independent market share 2010–2017





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27

As with Shell, both Vattenfall and ENGIE preceded their GB domestic

market entry with recently developed EV charging capabilities

– through the launch of the inCharge network and purchase of

EV-Box respectively. E.ON UK has joined the ranks with its plan to

establish 10,000 UK charge points by 2020. With Ovo Energy and

Ecotricity already offering established domestic and public charging

propositions and Iberdrola reportedly looking to join the sector,

the EV-enabled electricity supplier landscape is beginning to look

increasingly busy.

With EVs estimated to reach cost parity with traditional combustion

engine vehicles by 2025 (Morgan Stanley) or even earlier (UBS), this

growing attention is unlikely to dissipate. With a growing number of

suppliers looking to develop broader energy services propositions, the

services required for and from EVs appears an increasingly attractive

market for technology-focused suppliers to diversify into.

The domestic charging of EVs represents a complementary service

to traditional energy supply, as it should allow EV owners to provide

‘vehicle to grid’ services that include charging and discharging in

response to wholesale price signals and network needs, and can

fit well with the large number of solar panels already deployed in

households. Meanwhile, the establishment and operation of public

charging networks offers an opportunity for suppliers to gain a

foothold in an adjacent space, where scale and existing infrastructure

offers a competitive advantage. A number of suppliers and local

authorities are actively exploring opportunities in this area.

Shell’s acquisition of First Utility closely followed its purchase of

EV charging company New Motion in October 2017, as well as its

partnership with charging infrastructure operator IONITY. This put

the company in a well-placed position to build on these transactions

to further develop its public and domestic charging services, and

it announced the trial of rapid chargers at select forecourts in

October 2017.



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28

market opportunity by 2020, driven mostly by adjacent “smart

markets”, from connected kitchenware to smart sensors. The breadth

of current and potential future smart appliances, and the scale of

business opportunity to package services around them, is likely to

see smart homes becoming an area of considerable focus for forward

thinking energy suppliers.

Numerous suppliers have already entered the connected-home

market. Smart thermostats have been the first technology to take

off through the supplier channel, mostly through partnerships with

existing technology providers. Meanwhile British Gas opted to

develop Hive, its own smart home brand with offerings including

smart thermostats, cameras, and lighting.

The entry of the large technology companies, including Samsung,

Google, Amazon, and Apple, in the home hub market – the central

control point for many of the smart home offerings – provides a real

indication as to the likely direction of travel for the market.

The increasing use of technology at the domestic level has the

potential to benefit not only the energy supply sector but the

operation of networks. Aggregators have played an important role

in offering business consumers additional revenue and cost savings

by bundling multiple customer loads together to access balancing

services contracts from National Grid. As metering, communications

and control equipment is deployed at the domestic level it should be

possible for similar activities to be introduced at the household level.

Technological developments such as blockchain, and the so-called

“internet of things” – the ability of home devices to sustainably and

intelligently interact with real-time price signals or instructions from

the market – if adopted at scale have the potential to reduce network

and balancing costs with incumbent cost savings (and potential

revenue streams) flowing through to consumer bills. To realise those

benefits the wide adoption of time of use tariffs enabled by half-

hourly settlement is essential. That is not a given at this stage, and

the timescales for realisation of households, in aggregate, providing

network management services remains uncertain. The completion

of the smart meter roll-out, scheduled for December 2020, is a key

enabler.

Customer data and the way it is processed is central to the smart

home. As the smart home develops, the amount and quality of

data available to both consumers and their suppliers will grow

considerably. That data has real value. However issues around

ownership, access security and value are complex and multi-faceted.

Clear regulatory and governance frameworks will be needed to ensure

those issues are appropriately dealt with and consumer confidence is

not undermined. That is not an easy task but encouragingly Ofgem is

already considering what the issues may be and how they can best be

dealt with.

In addition to the electrification of transport, other technological

developments continue apace, and taken together have the potential

to disrupt and change the domestic supply market. The rise of the

“connected-home”, where consumers purchase equipment to give

them greater control of their consumption and on-site generation,

introduces a further vector for change for the sector. Like EVs the

mass installation of more sophisticated connected-home products

(e.g. through optimising heating and appliance use in response to

price signals, and potentially network management services) has

the potential to significantly change how consumers interact and

interface with the market.

The appetite for smart products is large and growing. Research by

E.ON UK in July 2017 reported that 73% of people have already

invested in some form of smart technology. It also appears to be a

lucrative market. According to bottom-up modelling by Accenture,

the connected-home sector offers energy suppliers a potential £2bn

Gus WoodPartnerGowling WLG

Much of the recent regulatory intervention in the retail sector has been unwelcome – driven by political point scoring rather than sound policy. However, amongst the noise of price caps, there have been positive steps. Smart meters may not represent a panacea, but they will certainly offer some opportunities for product innovation. Ofgem’s Switching Programme and the proposed new Retail Energy Code will also present an opportunity for a consolidated database of more accurate data, as well as a faster more reliable change of supplier process. These changes should combine to offer the conditions and opportunities for energy suppliers and disruptive technology providers to provide innovative new products and services. This is, therefore, a seminal moment where the need to collaborate and work harmoniously in conjunction with other industries and specialisms, could not be more pressing.


29

the market and the customer, remains fit for purpose given the rapid

emergence of technologies that are likely to fundamentally change

the energy support market in the future.

There is a clear concern that the current supplier hub model presents

little in the way of viable options for parties seeking to innovate in

electricity supply. The only current options being to enter into often

complex contractual arrangements with a willing supplier they trust

and who understands their proposal or become licensed themselves;

often not an attractive proposition for organisations who do not see

themselves primarily as energy suppliers.

Ofgem expects to provide an update on its thinking in the first half

of 2018. It is difficult to foresee the status quo being an acceptable

enduring solution. Depending on their scope, changes to the model

may see the supplier hub approach being cracked apart, providing

opportunities for ever increasing innovation in the retail sector.

Under current industry rules and codes, suppliers remain very

important actors in the sector. However the advancement of

technology in the smart home arena provides real opportunities for

new players to emerge, including entities that already operate in

domestic service sectors. Again, as this market diversification unfolds

and the benefits that it can bring become clearer, regulators and

policy makers will need to think creatively about the role policy and

regulation needs to play to facilitate (as opposed to inhibit) new

actors, non-traditional business models and technological innovation.

Ofgem’s thinking is already developing not least through its call for

evidence on the “Future Supply Market Arrangements”. The attendant

press releases and presentations were at least as illuminating as the

questions contained in the call for evidence. Of particular interest

was the questioning of whether the current ‘supplier hub’ retail

model in which the supplier is responsible for all interfaces between

What is the “supplier hub”?

The supplier hub gives the licensed supplier the responsibility to put in place arrangements for all necessary services to give effect to supply (e.g. wholesale trading and hedging, metering, paying network charges, account management), collect subsidy for low-carbon generation programmes, and for household suppliers with above 250,000 accounts, install energy efficiency measures and provide annual rebates via the Warm Homes Discount scheme.

This monolithic structure made sense at retail market opening by simplifying sector interactions from the consumer but overtime the supplier-hub has become engorged to include the deployment of smart meters, the collection of four separate subsidy programme costs, and for household suppliers above the 250,000 account threshold, the delivery of three components of the Energy Company Obligation thermal efficiency scheme.




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Cornwall Insight / Gowling WLG whitepaper \ Final conclusions

31

FINAL CONCLUSIONS

The potential for technology to unlock radically different means to

trade power, balance and manage networks, and for consumers to

interact with the market, are becoming clearer, but the possibilities

excite as much as certainty eludes.

We are in evolutionary and fertile times. Significant technology-

driven change across the energy value-chain is inevitable. However,

the precise combinations of technologies and business models that

will emerge from, provide shape to, and succeed in the electricity

market of the future is, at this point at least, difficult to determine.

Generation is moving towards a focus on the opportunity to stack

technologies and access a range of revenue sources, physically

or virtually. Storage is bridging the traditional bi-polar market of

producers and consumers and unlocking new markets. Networks are

becoming less conduits for power transportation, and more tools for

local balancing and smart matching of supply and demand. Retail

markets are digitally extending in-front of the meter and reaching

into transportation and home services. The lines delineating different

parts of the value chain are becoming more blurred, and if anything

the power market is showing the potential to be more a three-

dimensional and inter-operable mesh than a series of linear flows.

But whilst innovation is prolific, the speed of adoption, how orderly

it is and how quickly the market benefits from its application will

depend on the market structures and regulatory frameworks that

are put in place around them. Whilst technology and the innovators

have the ability to drive the sector forward for the benefit of all,

policy and regulation needs to not only keep pace but stay ahead of

the opportunity if it is not to act as a brake. That is a real challenge

and is likely to require a change of mind set amongst those who have

responsibility for setting the policy and regulatory agenda.

Developing technology and business models and the interest of

entrepreneurial new actors in the sector provides an opportunity to

restructure and reimagine the sector’s organisational architecture –

indeed doing so will be a necessity if the sector is to flourish. But it

would be naïve to assume that the edifice of the current market can

be reformed overnight. The generation, production, distribution and

consumption of energy is a key factor in social cohesion, economic

well-being and even national security. Measured transition rather

than rapid revolution is likely to be the order of the day, no matter

how far and how quickly innovators look to push the boundaries.

The focus of policymakers and those engaged in regulating and

creating markets should be to create models based on orderly and

thought-through change, which, where appropriate, facilitates rather

than constrains innovation. It is important that legacy interests do

not stifle that change.

The appetite of financiers and investors to quickly embrace new

funding models in an environment based on market opportunity

rather than subsidy will also be key. The days of assessing investment

risk against long-term, stable subsidy-backed returns are unlikely to

be seen again for some time, if at all.

New and existing projects are already coming to terms with a world

where accessing multiple, often short-term revenue streams, which

are subject to increasing regulatory review, is essential to delivering

acceptable returns. Funding models (and funding structures) are

being adapted to reflect that, with equity playing a much bigger role.

That, combined with increasing concerns about stability in policy

and regulation may well result in a higher cost of capital with the

consequential impact on asset deployment. Funders can deal with

risk they understand, but the constant fear of the goalposts being

moved is a step too far for many. It is essential that policymakers

agree a consistent set of principles to support their policy objectives,

and once the rules of the game have been made do not change them.

The ingredients for a transformation in the electricity market are all

present: technological innovation, market volatility and numerous

and diverse new entrants. As a result, in the history of the British

electricity sector, future commentators are likely to look back

at the turn of this decade as the end of one chapter – national,

renewable proliferation – and the start of another – decentralised and

smart digitalisation.

Whatever form it takes, given the state of development and the march

of technology and innovation, we are almost certainly on the cusp of a

fundamental re-writing of the sector as we currently know it.

Gowling WLG is an international law firm comprising the members of Gowling WLG International Limited, an English Company Limited by Guarantee, and their respective affiliates. Each member and affiliate is an autonomous and independent entity. Gowling WLG International Limited promotes, facilitates and co-ordinates the activities of its members but does not itself provide services to clients. Our structure is explained in more detail at www.gowlingwlg.com/legal

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CORNWALL INSIGHT / GOWLING WLG WHITEPAPER · Cornwall Insight / Gowling WLG whitepaper \ Foreword 1 FOREWORD The electricity sector is experiencing change at a pace and of a nature