Part 3: NETA, a new decade but old habits by Nigel Cornwall


IN this series of four features, Nigel Cornwall is taking us on a journey over the 30-year history of GB Electricity Market.

Nigel Cornwall is a well-known energy industry commentator and founder of Cornwall Insight.

His latest venture is New Anglia Energy, which is a company formed to support local energy markets in Norfolk and Suffolk.

Its purpose is to demonstrate learning by doing, using the knowledge and relationships developed by Nigel in a long and fruitful career in the energy sector to support local stakeholders and initiatives.

The first part of the series can be read here

Part two can be read here

The introduction to the four features is available here




One step forward, and a few sideways shuffles

“Our previous piece – the second in this series of four on the electricity trading arrangements in Britain at 30 – considered the first 10 years of NETA, including its extension into Scotland.

It explained why pressures for faster, more strategic change mounted.

Indeed, the decade finished with the first of Ofgem’s Code Governance Reviews.

This review focused on the Balancing and Settlement Code (BSC) and establishment of the regulatory Significant Code Review (SCR) mechanism, which was intended to facilitate Ofgem’s wider energy reform agenda.

But, contrary to expectations prevailing around that time, subsequent changes since have not delivered any major change under the BSC with a handful of notable exceptions.

The biggest exception concerns energy imbalance pricing (or electricity “cash-out”) reform.

After much tinkering during the 2000s, this underwent major revision in 2015 with a shift to a single imbalance price and establishment of rules to sharpen prices during high demand periods (sometimes called scarcity pricing).

There have been other significant changes: these include a change to the pricing of transmission losses, from costing these on an average national to marginal regional basis, which was achieved after over 20 years of pressure from market reformers.

The introduction of market-wide half hourly settlement for non-domestic customers has also taken place.

But these moves have been controversial to some, and of themselves have raised important questions around code change processes.

In this piece we focus on these headline changes that have occurred over the past decade, and then turn to the sustained regulatory attempts over the period to streamline governance.

This will establish our baseline for the fourth and final piece next time, which will address current challenges and my take on necessary changes going forward if we are to have any chance of the sector contributing appropriately to delivering the net zero target.

Fixing a hole

Since 2010, there has been a continuing and steady flow through of code changes, numbering upwards of 150.

Many have represented sensible change, with process enhancements and fine-tuning; but none have presaged the major shift in the rulebook that is needed to deliver the smart, flexible system central to the policy view. Above all the system remains heavily centralised, and the demand side is essentially passive.

Undoubtedly the highlight centred on further mechanistic change to imbalance pricing. The first SCR to impinge on the BSC was the “Electricity Balancing SCR”.

Following delivery of the powers under the first Code Governance Review and concerns on market functioning set out in Ofgem’s 2010 maligned Project Discovery report, it took nearly 18 months to consult on the scope of the review, which was then kicked off formally in August 2012.

In setting out its scope, Ofgem talked about problems with dampened and inaccurate price signals that undermined incentives to balance and invest.

It also noted significant challenges and imminent changes to wider energy markets, including changes take place to the European Internal Market.

Ofgem’s final policy decision on the EBSCR was issued in May 2014, and it directed National Grid to raise changes to give effect to the conclusions.

These highlighted those defects that increased the cost of ensuring security of supply and undermined the incentives this created for efficient balancing but also dampened incentives for the market to provide flexibility in an increasingly intermittent system.

The modification, which became P305, had four core components.

These were: a reduction in the volume of balancing actions used to set imbalance prices; a shift from two (dual) prices to a single cash-out price; the introduction of security-based costs in imbalance prices through the incorporation of disconnections and voltage reduction; and, pricing in short-term operating reserves into the cash-out price calculation.

The reforms were implemented in two phases.

First by reducing the volume of actions taken by the system operator and included in the price setting – the so-called PAR volume – from 500MWh to 50MWh in November 2015, alongside an initial cap of £3,000/MWh.

This was to be followed, subject to assessing how the phase 1 changes worked, by a shift to 1MWh of balancing actions and a cap of £6,000/MWh for phase 2 from November 2018.

The reforms operated largely as expected during phase 1, according to an assessment by Ofgem published in in August 2018.

Not surprisingly Ofgem found that, although imbalance prices were on average lower following implementation of P305, they had become sharper and were higher when the system was short and lower when the system was long, which was precisely what was intended.

The system was slightly longer on average, and it was long for more periods.

Reserves were added into the calculation only twice in the two years following the first wave of EBSCR changes (which was less than expected), and there were no demand control events.

The regulator said that prices had not risen or fallen to levels it was concerned about, although imbalance volumes had increased in both absolute and net terms, with overall imbalance charges falling from £120m to negative £25m.

On the basis of this assessment, it agreed with phase 2 of the reforms being implemented in November 2018 on schedule, and there has been no focused review since.

Huffing and puffing

As for other major changes to the rulebook during the 2010s, these can be counted on the fingers of one hand.

Some of the other standout changes in terms of market design are summarised below.

The issue of charging for transmission losses has been a controversial issue in Britain for many years.

Total network losses account for around 10% of energy supplied, with about a fifth of these attributable to the transmission system.

However, all transmission losses were allocated on a socialised basis to everyone that used the transmission system.

They were allocated at a flat rate each half hour based on the volume of energy that each party was responsible for – whether delivering energy to the system (in the case of generators) or taking it (in the case of suppliers).

Despite a clear regulatory desire for change and for a move to more locational, cost-reflective arrangements, several change proposals have been brought forward but blocked by the industry (or rather by those parts that would have lost out) or failed to get through judicial review.

However, the Competition and Markets Authority as part of its energy sector investigation in 2014-15 examined the issue again and endorsed the need for change.

National Grid accordingly brought forward  BSC modification proposal P350, which was implemented in April 2018.

Since then about half of all transmission losses have been charged on a regional basis by 14 zones based on modelled seasonal loss factors set in advance of the year.

Each zone has a different “correction factor” set in advance of the year based on forecast power flows that is reset each season applied to metered energy volumes with generators’ metered volumes being grossed down and suppliers’ metered volumes being grossed up.

For zones that have a large disparity between generation and demand, this correction factor can be large.

Thus for a generator located in a zone dominated by generation (e.g. a wind farm in Scotland) will be penalised for causing more transmission losses, but demand in this same zone will be credited: vice versa for zones where there is a lot of demand but little generation (e.g. London).

The cutover between the previous regime and the newly implemented regime was stark for many.

For example, transmission-connected generators in the north of Scotland saw their annual average cost exposure more than double.

Equally transmission-connected generators in several of the zones in the midlands and southern England have seen their liability for transmission losses reduce significantly, even to the extent that many now see it as a net benefit.

Distribution-connected generators and end consumers on the other hand are affected in very different ways – again with some losers (end consumers in the south) and some winners (embedded generation in the south and end consumers in the north).

On the supplier side, the most significant change under the BSC after cash-out reform over recent years was P272.

This change applied to all business (i.e. non-household) meters that used profiles.

It was introduced by Smartest Energy in May 2012, but it took almost five years to achieve implementation in April 2017.

Essentially, P272 requires that all businesses in what was termed profile classes 5-8 to have their energy use recorded every half hour and settled on that basis.

Despite a very difficult assessment process, it is regarded as one of the most significant changes in the business energy market since deregulation.

P272 was noteworthy for two particular reasons.

First, the process was undoubtedly considerably longer than needed because the large suppliers dominated the modification group formed to assess the change proposal.

Several were opposed to the change, and they developed a truck load of reasons why the change did not give rise to net benefits and consistently argued it should be rejected on cost grounds.

Second, it re-emphasised problems around industry governance known for some time, namely the interaction with other codes, and it took some time to work through the ramifications and necessary non-BSC changes needed (notably to the Connection and Use of System Code (CUSC) but also the Distribution Connection and Use of System Code).

Even after Ofgem approved the change, there was a further modification needed, which slipped the final implementation date to April 2017 because of some of the wider interactions.

Interestingly, Ofgem has since instigated a workstream on “market-wide half-hourly settlement” to consider how profile classes 1-4 (mostly domestic meters) can similarly be moved to more granular settlement.

There remain some critical hurdles to navigate, as we will consider next time, and the timetable has already been subject to delay.

But this time regulatory support for the direction of the work has been set out at the outset, and the regulator has been much better able to drive the scope and pace of this work.

An enduring problem

A key feature of the NETA design was flexible governance and the ability for the rules to change in the light of a changing system and rapidly evolving policy.

Indeed, Sir David Currie, one of the three independent advisers who guided the design process, talked in 2000 about NETA being “half a market”.

This was not meant to be disparaging, rather that the governance was established to provide adaptability, to avoid the rigidities of Pool governance.

But, as we saw last time, in practical terms change has not been much more forthcoming under NETA.

In 2007 Ofgem had kicked off a CGR, the first of three that since taken place.

This was triggered by two main concerns.

First, there were problems amending codes to support the delivery of major reforms in key policy areas (notably the Transmission Access Review, which had drifted on under the CUSC without closure for some time, but also more widely the increasing emphasis on environmental objectives in Ofgem’s principal objective and duties), especially where they cut across different codes.

Second, code processes were considered fragmented and complex, which made it difficult for smaller players and new entrants to participate.

Take 1

The first phase of the CGR focused on the BSC, the CUSC and the Unified Network Code (UNC) and ran from 2007 to 2010.

This established the basic reforms made by Ofgem for the major codes, and these were then extended to the other codes in a second phase running from 2010 to 2013.

As part of the initial phase, Ofgem commissioned a study of the existing governance arrangements by consultants the Brattle Group and lawyers Simmons and Simmons.

The main conclusion of the study, which the regulator accepted, was that there was a fundamental flaw in code governance arrangements, which have significant implications in areas that are not purely, or even mainly, commercial but form part of public policy.

There were also concerns expressed about the quality of assessment of the impacts of modification proposals, and the burden placed on smaller actors by the fragmentation and complexity of code governance arrangements.

The CGR led to Ofgem introducing a number of changes.

The first change was a splitting of the modification process into three tracks.

One was for minor modifications with ‘non-material’ impacts, which would be handled entirely by industry on a fast-track self-governance route that did not require Ofgem’s final approval.

The second track was for modifications that did have more major consequences for parties, which would be handled more or less in the usual way.

The code panels would determine whether a change proposal raised by a party should go down a fast-track self-governance route or the reformed status-quo route, subject to Ofgem’s veto on that decision.

Third, and crucially, for major changes where Ofgem took the view that policy change and the carrying out of its duties required, the regulator was empowered to instigate the SCR process.

In this process Ofgem would carry out analysis of changes needed and their likely impacts.

It could not raise change proposals itself but could direct a licensee to raise them on its behalf, and it would retain final decision powers.

Thus, the SCR process provided a tool for Ofgem to initiate wide-ranging change and to implement reform to a code-based issue.

An SCR has to be launched through issue of a direction to National Grid, and any new modification proposals addressing similar issues could not ordinarily proceed through the standard industry modification process.

Ofgem can also in exceptional circumstance issue a “backstop direction”, where development of the modification proposal under the standard industry code process is not meeting the expected policy direction or timescales for implementation.

A fourth important change arising from the first CGR was reform of code administration.

The review brought in a Code Administration Code of Practice (CACoP), which set out principles and processes that administrators were expected to follow.

The objective here was to standardise and make more transparent the range of processes across codes.

The CACoP also specified that code administrators such as Elexon should act as “critical friends”, paying particular attention to under-represented parties, small market participants and consumer representatives.

Further CGR reforms included bringing of network charging methodologies into the code governance process in order to allow network users and consumer representatives to formally propose modifications to those methodologies.

Take 2

Despite these changes, many of the issues identified around code governance were not resolved.

Ofgem accordingly relitigated its concerns through the energy market investigation conducted by the Competition and Markets Authority (CMA), opened in June 2014.

High energy prices and concerns about lack of transparency and possible collusion in energy markets had been rising up the regulatory agenda over the previous few years.

In its initial submission Ofgem raised the concern that, despite the CGR reforms, industry codes could act as a potential barrier to competition due to the regulatory burden of compliance with and participation in code governance which would be disproportionately heavy for smaller participants.

There was also a concern that because code governance remained largely industry-led, there would be no incentive for change in this situation from within the system.

The CMA issued a working paper on codes in February 2015 that extended the scope of the investigation into a “fifth theory of harm”.

Its focus was on how industry codes affect competition.

In July it published its provisional findings, arguing that code governance gave rise to an adverse effect on competition through limiting innovation and causing energy markets to fail to keep pace with regulatory developments and other policy objectives.

It then laid out a set of possible remedies, which included making code administration and implementation of changes a licensable activity, giving Ofgem more powers to project-manage the process of developing and implementing code changes.

This included a new proposed power to appoint an independent code adjudicator to determine which code changes should be adopted in the case of dispute.

Parallel to the CMA energy markets investigation, Ofgem launched its own further review of code governance in May 2015.

Despite the changes under the CGR, it still had concerns about difficulties for smaller parties, concerns about quality of industry analysis, coordination of modifications across codes and whether the code governance system sufficiently protected consumers’ interests.

There were also concerns that the system was not sufficiently flexible to meet the changes facing the industry, including the move to smart metering, the introduction of European network codes, the development of decentralised generation and the rise of non-traditional business models.

Recognising that the CMA was considering the whole codes system, Ofgem’s review was focused on incremental changes to the reforms that had already been introduced.

These included a backstop power for it to have a more proactive drafting and management role in SCRs, further changes to code administration, and a clearer requirement for modifications to explicitly consider impacts on consumers.

Ofgem also undertook a programme of engagement with industry to develop reforms to code governance.

In November 2016, it published an initial consultation on implementing the CMA’s recommendations on industry code governance.

This consultation proposed licensing of code managers and delivery bodies, setting a strategic direction for code development and establishing and running a consultative board to coordinate cross-code changes.

Unfortunately this momentum that developed over more than a decade has more recently been, if not lost, dissipated.

Legislative action was contingent on sufficient parliamentary time, but that disappeared with the general election of 2017, and then a fixation with getting Brexit done supplanted all non-essential legislative action.

Take 3

Not all bets are off. Following the Conservative return to government following the snap 2017 election, BEIS with Ofgem launched a “joint comprehensive review” aimed at developing options for improving code governance.

Following stakeholder workshops in early 2019 it issued its Consultation on reforming the energy industry codes in July. In it it identified challenges that “make a powerful case for change if we are to avoid … outcomes, stifling innovation and competition as the energy system adapts to the challenges of the coming decades”.

In the consultation, BEIS/Ofgem identified three potential packages of reforms as potential options for change.

This listed with increasing degrees of change: process improvements with evolutionary changes to the current situation and under which existing responsibilities and accountabilities would be maintained; substantial reform of the codes system, including potentially changes to the current code model; and, taking a different approach and moving away from codes, with potentially new bodies with new powers.

The consultation also considered how to provide better strategic direction.

Two basic models were considered: a strategic body that was separate from the code manager; and, an integrated rule making body that functioned alongside but separate from code management.

Although the consultation closed in September nothing further has issued from either BEIS or Ofgem.

The intention had been to distil the findings and some conclusions into the energy white paper that has been successively delayed, but which could emerge towards the back end of this year.

Unfinished business

There is a growing sense among some commentators, including this one, that the current trading arrangements are well out-of-step with wider economic, environmental and societal changes.

There have been few major changes to the rulebook in a fast-changing industry, and those that have occurred have been fractious and taken far too long to be realised.

There is a growing and high level of disaffection among new types of player that their interests are systematically subordinated and that attempts to bring benefits of innovation for customers are being frustrated.

There is also a growing body of opinion that the tone of the joint review of governance suggested expectations on the degree of change are being lowered.

Surprisingly the level of ambition in the 2019 consultation seemed to be more anchored on delivering the new Retail Energy Code and faster switching next year rather than a pathway to the new net zero by 2050 target that was adopted ahead of its release.

If so, this would be unfortunate as structural issues around code governance and notably the BSC are plain for all to see, and what already looked like a stuttering system in 2010 is much less fit for purpose today.

Indeed, a clear lesson of the COVID-19 pandemic is that the system increasingly dominated by intermittent generation is not well-placed to deal with unforeseen changes and system stresses.

Linkages with heat and transport are also now emerging as a priority area in a system that needs to considerably ramp up flexibility and demand-side response, and in which more joined up planning is now an imperative.

In conclusion, both in terms of market change and governance reform, the dominating sense of the past decade is that it has been a lost opportunity, and the need for better responsiveness and bold action is now unavoidable and urgent.

“We will address what this might look like next time.”