CORNWALL INSIGHT / GOWLING WLG WHITEPAPER · Cornwall Insight / Gowling WLG whitepaper \ Foreword 1...
Transcript of CORNWALL INSIGHT / GOWLING WLG WHITEPAPER · Cornwall Insight / Gowling WLG whitepaper \ Foreword 1...
HIRES LOGO VERSION REQUIRED
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
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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
Cornwall Insight / Gowling WLG whitepaper \ Introduction
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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.
Cornwall Insight / Gowling WLG whitepaper \ Introduction
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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.
Cornwall Insight / Gowling WLG whitepaper \ Introduction
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Cornwall Insight / Gowling WLG whitepaper \ Generation
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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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Figure 3: cumulative plant retirement forecast, net of interconnector additionsSource: BEIS
Cornwall Insight / Gowling WLG whitepaper \ Generation
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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
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DECC 2013
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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
Cornwall Insight / Gowling WLG whitepaper \ Generation
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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.
Cornwall Insight / Gowling WLG whitepaper \ Generation
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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.
Cornwall Insight / Gowling WLG whitepaper \ Generation
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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
Figure 3: cumulative plant retirement forecast, net of interconnector additions
Source: Cornwall Insight analysis
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Cornwall Insight / Gowling WLG whitepaper \ Generation
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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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Figure 5: Residential Heat Pump Peak Electricity Demand
Figure 7: Timeline of EV commercial model development Nov 2016 to Dec 2017
Figure 4: day-ahead price volatility 2013 to 2018
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
Cornwall Insight / Gowling WLG whitepaper \ Generation
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
www.cornwall-insight.com
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
Cornwall Insight / Gowling WLG whitepaper \ Generation
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.
Cornwall Insight / Gowling WLG whitepaper \ Generation
13
Cornwall Insight / Gowling WLG whitepaper \ Generation
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.
Cornwall Insight / Gowling WLG whitepaper \ Networks
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”?
The range of Electric Vehicle impacts on demand
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Predictions for the rate of increase of EV demand have risen dramatically over the past few years, as shown in the graph that tracks National Grid’s forecast view on EV demand between 2014 and 2017.
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.
Figure 5: Residential Heat Pump Peak Electricity Demand
Source: National Grid
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Figure 5: Residential Heat Pump Peak Electricity Demand
Figure 7: Timeline of EV commercial model development Nov 2016 to Dec 2017
Figure 4: day-ahead price volatility 2013 to 2018
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
Cornwall Insight / Gowling WLG whitepaper \ Networks
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.
Cornwall Insight / Gowling WLG whitepaper \ Networks
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.
Cornwall Insight / Gowling WLG whitepaper \ Networks
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
www.cornwall-insight.com
1
Wind Solar Thermal
Load/ demand Storage Control centre
Diesel
www.cornwall-insight.com
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.
Cornwall Insight / Gowling WLG whitepaper \ Networks
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.
Cornwall Insight / Gowling WLG whitepaper \ Networks
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.
Cornwall Insight / Gowling WLG whitepaper \ Networks
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.
Cornwall Insight / Gowling WLG whitepaper \ Networks
23
Cornwall Insight / Gowling WLG whitepaper \ Networks
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.
Cornwall Insight / Gowling WLG whitepaper \ Retail markets and consumption
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
Source: Cornwall Insight analysis
Figure 6: Number of GB suppliers and independent market share 2010-2017
What is the “Supplier hub”?
The range of Electric Vehicle impacts on demand
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Cornwall Insight / Gowling WLG whitepaper \ Retail markets and consumption
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.
Figure 7: Timeline of EV commercial model development Nov 2016 to Dec 2017
Source: Cornwall Insight analysis
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Figure 5: Residential Heat Pump Peak Electricity Demand
Figure 7: Timeline of EV commercial model development Nov 2016 to Dec 2017
Figure 4: day-ahead price volatility 2013 to 2018
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
Cornwall Insight / Gowling WLG whitepaper \ Retail markets and consumption
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.
Cornwall Insight / Gowling WLG whitepaper \ Retail markets and consumption
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.
Figure 6: Number of GB suppliers and independent market share 2010-2017
What is the “Supplier hub”?
The range of Electric Vehicle impacts on demand
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SaMS Large suppliers
Need confirmation on this one but will send over teh confirmed version
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Cornwall Insight / Gowling WLG whitepaper \ Retail markets and consumption
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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