Energy Act 2013: 5 year review

Question 1

Introduction

Accepted Answer

This review was completed in 2019 and should be read as such. Publication of this review has been delayed for several reasons, including the UK’s withdrawal from the European Union and the COVID-19 pandemic. Some aspects of the review have been updated (for example, to reflect more recent climate change targets). However, it has not been possible to update the full review because this would have added significant further delay to publication.

The Energy Act 2013 introduced a legislative framework for delivering secure, affordable and low carbon energy. One of the aims of the act is to ensure that, as older power plants are taken offline, the UK remains able to meet its energy demands whilst decarbonising.

Section 66 of the act contains an obligation:
1. As soon as reasonably practicable after the end of the period of 5 years beginning with the day on which this Act is passed, the Secretary of State must carry out a review of the provisions of the following chapters of this part —
  1. (a) chapter 2 (Contracts for Difference)
  2. (b) chapter 3 (capacity market)
  3. (c) chapter 5 (conflicts of interest and contingency arrangements)
  4. (d) chapter 6 (access to markets)
  5. (e) chapter 7 (the renewables obligation: transitional arrangements)
  6. (f) chapter 8 (emissions performance standard)
The Secretary of State must set out the conclusions of the review in a report.
The report must, in particular -
1. (a) set out the objectives of the provisions of each chapter subject to review
2. (b) assess the extent to which those objectives have been achieved, and
3. (c) assess whether those objectives remain appropriate and, if so, the extent to which those objectives could be achieved in a way that imposes less regulation.
The Secretary of State must lay the report before Parliament.
Section 151 of the act also contains an obligation to review:
1. (a) section 144 and schedule 14 (consumer redress orders)
2. (b) section 149 (fees in respect of decommissioning etc)

Question 2

Electricity Market Reform (EMR) statement

Accepted Answer

Electricity Market Reform (EMR) was designed to enable the UK to develop a clean, diverse and competitive mix of electricity generation that will ensure we meet our targets on decarbonisation and security of supply, while keeping bills as low as possible for consumers now and in the future. Without reform, it was assessed that electricity prices would have become increasingly volatile, the risks of the lights going out would have increased and significant volumes of low carbon electricity generation at lower prices may not have come forward.

EMR introduced two major policies to deliver these aims:

Capacity Market (CM): To ensure security of electricity supply at the least cost to the consumer
Contracts for Difference (CfD): To provide long-term revenue stabilisation for new low carbon electricity generation in Great Britain (GB).

Both schemes are administered by delivery partner National Grid Electricity System Operator as the EMR Delivery Body. The Low Carbon Contracts Company (LCCC) manage CfD contracts and the Electricity Settlement Company handle CM payments.

These two major policies are supplemented by the smaller policies of Conflicts of Interest and Contingency arrangements, Access to Markets, Renewables Obligation Transitional Arrangements and Emissions Performance Standard (EPS).

What has EMR achieved?

Decarbonisation

Under the CfD scheme, three allocation rounds have been held to date. This review focuses on allocation round 1 (AR1) and allocation round 2 (AR2), as these have taken place in the 5 years since the 2013 Energy Act was introduced. The externally led CfD Evaluation will continue to review the outcome of allocation round 3 (AR3), which awarded contracts to 5.8GW of new renewable electricity capacity that will be added to the grid by 2025.

For CfD AR1 and AR2, in total 5.48GW of capacity has been awarded. The capacity awarded in AR1 and AR2 CfD will contribute 1.3% of all electricity generation by 2020, based on the January 2019 CfD register, and by 2025 this is estimated to increase to 6% of the UK’s total electricity generation. Furthermore, the scheme has contributed to the UK currently being on track to meet the government’s aim of generating 30% of electricity from renewable sources by 2020. As a result of a bi-lateral CfD, the UK’s first nuclear project in a generation is in the process of being built.

Since the introduction of the Emissions Performance Standard (EPS), which complements decarbonisation measures such as the carbon price support scheme and the National Planning Policy framework, and places an emissions limit on new fossil fuel plants, no new coal plants have been constructed.

The CM has ensured that an adequate level of security of electricity supply is delivered in a way that is cost-effective and complementary to decarbonisation policies. To ensure that the CM can continue to achieve its objective to complement decarbonisation policies, and to maintain technology neutrality within the CM, in June 2019 we made changes to enable certain renewables that are not in receipt of other forms of subsidy to compete in the auctions. In July 2019 we made changes to introduce a carbon emissions limit into the CM. The limit applied to new build plants from July 2019 and will apply to existing plants from 1 July 2025 at the latest.

On 15 November 2018, the General Court of the Court of Justice of the European Union annulled the European Commission’s July 2014 State aid approval of Great Britain’s (GB’s) CM^{[footnote 1]}. This judgment resulted in the imposition of a standstill period on the CM while the European Commission carried out an in-depth investigation to gather more information on certain elements of the CM. On 24 October 2019 the European Commission satisfactorily concluded its investigation and concluded that the CM (as it had operated since 2014, including during the investigation period) complied with EU State aid rules^{[footnote 2]}, bringing the standstill period to an end.

Security of supply

To date the CM has run eleven rounds of auctions, including two dedicated auction rounds for demand side response (DSR) and distribution connected generation. The auctions have secured the large majority of our capacity needs out to 2022/23 at low clearing prices (the remaining capacity needed for each delivery year will be secured through the upcoming auctions held one year before delivery (T-1)). There have been no electricity stress events since the implementation of EMR and we have consistently met our reliability standard^{[footnote 3]}.

Keeping bills as low as possible for consumers

The CfD 15 year price stabilisation mechanism has contributed to the scheme meeting its initial policy objectives of increasing investor confidence. This has provided more certainty over future revenue, reducing risks for investors, and therefore leading to lower cost of capital for developers.

Clearing prices for future offshore wind projects have fallen from £114.39/MWh in the 2015 allocation round to £57.50/MWh in 2017 (2012 prices). This reduction was faster than historical or international trends.

AR3 results have shown that clearing prices for offshore wind have reduced by around 30% since AR2 and around 65% since AR1 (to £39.65/MWh in 2023/2024 and £41.611/MWh in 2024/2025).

In comparison to the predecessor policy of the Renewables Obligation, CfD projects in AR1 and AR2 are estimated to deliver a saving of around £3bn up to 2050 (with a range of £1bn to £4bn in tested scenarios)^{[footnote 4]}.

Since its implementation, the CM has been highly cost effective. Liquidity and competition within the capacity auctions have been high and auction clearing prices have been lower than expected. The most recent main auction (T-3 held in January 2020) cleared at £6.44/kW and the most recent top-up auction (T-1 held in February 2020) cleared at just £1.00/kW. This has resulted in low costs to the consumer.

In terms of the achievements of the smaller supporting policies of EMR, many have not yet been used. Given that these are deterrent or contingency policies, it is thought that as there has not been a requirement to use these policies, they are achieving their intended objectives.

Next steps

This review has evidenced that the EMR policies remain fit for purpose. The cost of renewables has fallen and is anticipated to fall further, however there is still expected to be a need for government support going forward.

By 2050 the UK will need to have met our world leading net zero emissions target; the power sector is vital to that. Whilst we cannot predict today exactly what the generating mix will look like in 2050, we can be confident that renewables will be the foundation of this, alongside firm or flexible low carbon generating capacity such as carbon capture and storage technology and nuclear power stations.

Net zero defines what we must achieve by 2050, and the Net Zero Strategy sets out how to get there. We must take the necessary decisions now to deliver the low cost and secure low carbon power system we will need to reach net zero.

To build on the success of the CfD scheme, the fourth allocation round (AR4) was launched on 13 December 2021.

To ensure security of supply there is a strong need to maintain the CM going forward, given that many of the underlying issues that led to its introduction continue. In particular, the significant coal and nuclear plant closures expected in the 2020s, the persistence of the ‘missing money^{[footnote 5]}’ problem and the rapid evolution of the electricity system in GB.

A call for evidence held in 2018^{[footnote 6]} highlighted several areas for minor improvement in the CM, in particular, to ensure that competition in the CM continues to be based on a level playing field between technologies, to further improve the cost-effectiveness of the scheme and to make simplifications where possible. Full details of our plan for making these minor improvements to the CM can be found in the Five-Year Review of the CM which we published in July 2019^{[footnote 7]}.

Many of the smaller, supporting policies of EMR have not yet been used. However, given that these are deterrent or contingency policies, it is thought that even though there has been no requirement for their use, they are still fit for purpose.

We are continually seeking to understand whether we should adapt and improve our policy mechanisms, and the findings of this review have been integrated into work assessing how our policy framework can best deliver a net zero consistent power sector, including informing:

consultations on the design of AR4^{[footnote 8]}
the call for evidence on enabling a highly renewable electricity systems, which focused on broader, longer-term issues beyond AR4, including introducing greater exposure to market price signals^{[footnote 9]}
the energy white paper, which was published in December 2020 and set out an ambitious policy programme to put us on track to delivering net zero emissions by 2050^{[footnote 10]}
the Net Zero Strategy, which was published in October 2021 and built on the energy white paper, setting out how we will decarbonise all sectors of the UK economy.

Annex

chapter	policy overview
Contracts for Difference	the Contract for Difference (CfD) scheme aims to tackle the lack of investment in low carbon electricity generation allowing the government to achieve its objectives under the Electricity Market Reform to: - ensure the future security of electricity supplies - drive the decarbonisation of our electricity generation - minimise costs to the consumer
Capacity Market	The Capacity Market was introduced to mitigate future risks to the security of electricity supplies
Conflicts of interest	This policy gives the Secretary of State power to amend the national system operator’s transmission licence to introduce business separation or ring-fencing measures
Access to Markets	This policy enables the government to intervene in the market to address the problem of low levels of liquidity in the wholesale power market and the difficulties faced by independent generators in securing long-term contracts for the sale of their electricity
Renewables Obligation: Transitional arrangements	The Renewables Obligation (RO) was the main financial mechanism by which government incentivised deployment of large-scale renewable electricity projects in the United Kingdom. It came into effect in 2002 in Great Britain and 2005 in Northern Ireland. It closed to new capacity on 31 March 2017 (with exceptions that extended the deadline for certain projects to January 2019 in GB, and March 2019 in NI). Newly accredited capacity will receive support for 20 years or until the final closure of the scheme on 31 March 2037, whichever is the earlier
Emissions Performance Standard	The Emissions Performance Standard (EPS) imposes an “emissions limit duty” on operators of new fossil-fuel plant
Policy and Strategy Statement	This chapter introduces a strategy and policy statement, which will set out the government’s strategic priorities for the energy sector in Great Britain, describe the roles and responsibilities of various players who implement, or are affected by, GB energy policy and describe policy outcomes which are to be achieved by the Authority and the Secretary of State when regulating the sector
Consumer Protection and Miscellaneous	This policy provides Ofgem with powers to compel energy companies found to be in breach of licensing conditions to issue redress to affected consumers. This section also covers the fees in respect to nuclear decommissioning

Question 3

Contracts for Difference

Accepted Answer

Post-Implementation Review title: Contracts for Difference
PIR number: BEIS012(PIR)-22-RE
Original IA/RPC No: DECC0144
Lead department or agency: BEIS
Other departments or agencies: n/a

Date: 17 June 2019
Type of regulation: domestic
Type of review: statutory
Date measure came into force: 18 December 2013
Recommendation: keep
RPC opinion: n/a

Contact details for enquiries: BEISContractsforDifference@beis.gov.uk

Summary

1. What were the policy objectives of the measure?

The CfD scheme is the government’s main mechanism for supporting low carbon electricity generation.

The objectives of the CfD were to:

ensure sufficient investment in sustainable low carbon technologies to put us on a path consistent with our 2020 renewables targets and our longer-term target to reduce carbon emissions by at least 80% of 1990 levels by 2050
maximise benefits and minimise cost to the economy as a whole and to taxpayers and consumers – maintaining affordable electricity bills while delivering the investment needed.

2. What evidence has informed the PIR?

This is a high evidence PIR because in allocation rounds 1 and 2 (AR1 and AR2) the annual budget allocated has exceeded £490 million. Furthermore, the scheme is strategically important in bringing forward low carbon electricity technologies in Great Britain and therefore has a high impact.

The PIR has been informed by an externally commissioned evaluation of the CfD covering the first two competitive allocation rounds. Semi-structured telephone interviews were conducted with 23 of the 38 CfD projects. 17 semi-structured telephone interviews were also carried out with wider developers of low carbon electricity projects who did not have a CfD contract. The analysis also compared the cost of the current CfD scheme with a modelled counterfactual scenario of subsidising the same level of generation under the previous Renewables Obligation policy.

The review has also been informed by a stakeholder workshop in January 2019. This brought together 24 stakeholders including academics, industry, investors and trade associations to discuss whether the scheme had met its original objectives and if these objectives were still valid.

The review of the nuclear CfD has been informed by the experience of BEIS officials working on this policy.

Phase 2 of the CfD Evaluation will explore Allocation Round 3 and Evaluation Phase 3 will synthesise the results of Phases 1 and 2.

The review has also been informed by a stakeholder workshop in January 2019. This brought together 24 stakeholders including academics, industry, investors and trade associations to discuss whether the scheme had met its original objectives and if these objectives were still valid.

The review of the nuclear CfD has been informed by the experience of BEIS officials working on this policy.

Phase 2 of the CfD Evaluation will explore Allocation Round 3 and Evaluation Phase 3 will synthesise the results of Phases 1 and 2.

3. To what extent have the policy objectives been achieved?

Overall the evidence suggests that the policy objectives are being met:

in total through AR1 and AR2 5.48GW of renewables capacity has been awarded contracts through the scheme. The capacity awarded in CfD projects from AR1 and AR2 are expected to contribute 1.3% to all electricity generation by 2020, based on the January 2019 CfD register. The capacity from the first two allocation rounds is estimated to provide around 6% of the UK’s total electricity generation by 2025
furthermore, the UK’s first nuclear project in a generation is in the process of being built as a result of a bi-lateral CfD
the 15-year price stabilisation mechanism has contributed substantially in meeting the policy aims of increasing investor confidence
analysis suggests that in comparison to the RO, CfD projects in AR 1 and AR2 are estimated to deliver a saving of around £3 billion (present value) up to 2050^{[footnote 11]}

We recommend that the policy is kept.

4. What were the original assumptions?

The July 2011 impact assessment^{[footnote 12]} reported that the expected economic impact of the CfD would lead to a more efficient allocation of risk among investors, consumers and government, by allocating risk to those parties best able to manage or control it. In particular, the CfD was assumed to be able to:

insulate investors in low carbon generation from fossil fuel price risk, which they are unable to control, thereby leading to a reduction in the cost of capital to investors relative to alternative support mechanisms and, in turn, reductions in the costs to society and consumers of securing this investment; but
maintain exposure to a fluctuating wholesale price for those technologies that are able to respond to this signal in their operational decisions

5. Were there any unintended consequences?

Overall the evidence suggests that the scheme has met its initial aims. However, through the review process areas were identified which stakeholders suggested if addressed could improve the effectiveness of the scheme. In particular, these relate to:

the pay-as-clear scheme design makes speculative bidding feasible
impacts of Milestone Delivery Dates on procurement practices and project risk assessments
the implications of not re-running pot 1 (for established technologies) since AR1
the ability of the CfD to support innovation

6. Has the evidence identified any opportunities for reducing the burden on business?

The CfD is an opt-in scheme for low carbon project developers, therefore any opportunities to reduce burden on businesses would be around the information and guidance association with the scheme. The majority of applicants (both successful and unsuccessful) found the information and guidance provided in advance of application was clear and sufficient to understand the requirements of participation.

7. For EU measures, how does the UK’s implementation compare with that in other EU member states in terms of costs to business?

N/A

1. What were the policy objectives of the measure?

Electricity Market Reform (EMR) was introduced as part of the Energy Act 2013. EMR aimed to incentivise investment in secure, low carbon electricity, increase the security of Great Britain’s electricity supply and improve affordability for consumers. The largest components of EMR were the Capacity Market (CM) and the Contracts for Difference (CfD). The CfD scheme is the government’s main mechanism for supporting low carbon electricity generation, following on from the Renewables Obligation (RO) which closed to new applications in March 2017.

The objectives of the CfD were to:

ensure sufficient investment in sustainable low carbon technologies to put us on a path consistent with our 2020 renewables targets and our longer-term target to reduce carbon emissions by at least 80% of 1990 levels by 2050
maximise benefits and minimise cost to the economy as a whole and to taxpayers and consumers – maintaining affordable electricity bills while delivering the investment needed

The CfD aims to give developers of large-scale low carbon projects a higher level of confidence and certainty to invest in low carbon electricity generation, by agreeing to a fixed price for the electricity output. The scheme aims to support investment in a wide range of low carbon technologies with different levels of maturity. The scheme allows investment to come forward at a lower cost of capital and uses an auction mechanism to deliver investment at a lower cost to consumers. For technologies such as nuclear, a bilateral CfD has been awarded.

Generators are awarded a 15-year CfD, with payments indexed to inflation, and a set of obligations to deliver the contracted capacity within a specified time period. The basic premise is as follows: the contract guarantees additional revenue to developers when the wholesale market price, the “reference price”, is below the “strike price”, which is a measure of the cost of investing in low carbon technology. At times when the reference price exceeds the strike price, the generator is required to pay back the difference, thus protecting consumers from over-payment.

As well as bringing forward low carbon projects, the scheme also encourages open and competitive supply chains, in which innovation and skills are promoted to drive down the cost of low carbon electricity generation over the long term, and lower costs for consumers. To facilitate this BEIS made the provision of an adequate supply chain plan a pre-condition for projects of 300MW and above to enter the CfD allocation process.

To deliver this scheme BEIS works with:

The Low Carbon Contracts Company (LCCC): Successful developers of low carbon projects enter into a private law contract with the LCCC^{[footnote 13]}, a government-owned company. The LCCC is counterparty to the CfD contracts, and its primary role is to issue and manage the contracts and make CfD payments
National Grid Electricity System Operator (ESO): As the Delivery Body for the CfD scheme, National Grid ESO^{[footnote 14]} is responsible for running the CfD allocation process
Ofgem: Ofgem^{[footnote 15]} is responsible for hearing certain appeals during the allocation process

2. What evidence has informed the PIR?

This is a high evidence PIR because for AR1 and AR2 the annual budget allocated has exceeded £490 million (£315 million^{[footnote 16]} in AR1 and £176 million^{[footnote 17]} in AR2; 2011/2012 prices). AR3 opened in May 2019, with an allocated budget of £65m (2011/12 prices) and overall capacity cap of 6GW. Furthermore, the scheme is strategically important in bringing forward low carbon electricity technologies in Great Britain and therefore has a high impact on delivering decarbonisation.

An external independent evaluation of CfD AR1 and AR2 was commissioned by BEIS to inform this PIR. The evaluation assesses the extent to which the CfD scheme is meeting its intended objectives and identifies how and why any intended and unintended outcomes are materialising for different technologies and developers. The evaluation provides an evidence base that can inform the ongoing design and delivery of the scheme, and addresses 5 high level questions:

to what extent, how and why is the CfD scheme contributing to its intended objectives, and do its outcomes, both intended and unintended, differ for different groups (project developers, investors, technology types)?
are the design parameters of the CfD scheme, including the allocation process, appropriate for achieving the intended objectives?
is the CfD scheme being delivered as intended?
does the CfD scheme present good value for money?
what are the implications of the findings for the future contribution of renewable technology to the electricity market?

Addressing these questions required a mix of impact, process and economic evaluation. The evaluation is theory-based, adopting principles of realist approaches to address questions around how differences in context influence how developers respond to the scheme. The evaluation used a combination of qualitative and quantitative data collection, and analysis to provide synthesised findings.

See the evaluation report and annexes with further information on the methodology and results.

Evidence sources

The following sources were used in the evaluation:

Scheme composition analysis:

This work package provided an initial analysis of the levels of electricity generation that CfD contracted projects are forecast to deliver to date.

Analysis of renewable energy investment trends:

Through analysis of existing secondary data sources (primarily the Bloomberg Terminal^{[footnote 18]}) this strand provided an analysis of trends in renewable investment between 2004-2018 to assess whether different types of firms have invested more/less in different technologies since the CfD scheme was introduced.

Rapid Evidence Assessment (REA):

The REA was used to consolidate existing evidence on the extent to which the CfD is delivering against its objectives, or ways in which processes for delivery may be improved. This strand reviewed international literature to give examples of how the design of renewable energy auctions has influenced the type of outcomes obtained.

Key stakeholder interviews:

Prior to mainstage fieldwork with low carbon project developers, an initial round of face-to-face interviews was carried out with CfD scheme policy leads and representatives of delivery partner organisations. This built understanding of the scheme’s design, its intended policy objectives, and the details involved in processes for delivering the scheme, including the roles of different delivery bodies. Eight key informant interviews were carried out in total, covering CfD policy and analyst leads in BEIS, and representatives of the LCCC, Ofgem and the National Grid ESO.

Interviews with CfD project developers:

Semi-structured telephone interviews were carried out with representatives of 23 of the 38 CfD projects awarded contracts in AR1 and AR2 (see table 1), including non-signatories and terminated projects. Some developer firms held contracts for more than one CfD generation unit. In addition, some offshore wind ‘projects’ are phased over time, which means that they are split into up to 3 individual generation units each with their own contract. In these cases, interviews were used to gather information on more than one project and generation unit per interview.

Table 1: overview of interviews with CfD developers:

Technology	AR1 projects covered through interviews (total awarded projects in brackets)	AR2 projects covered through interviews (Total awarded projects in brackets)	Total projects covered through interviews (Total awarded projects in brackets)
Advanced Conversion Technologies (ACT)	1 (3)	4 (6)	5 (9)
Dedicated Biomass with Combined Heat and Power (CHP)	0 (0)	0 (2)	0 (2)
Energy from Waste (EfW) with Combined Heat and Power (CHP)	0 (2)	0 (0)	0 (2)
Offshore wind	2 (2)	3 (3)	5 (5)
Onshore wind	10 (15)	0 (0)	10 (15)
Solar PV	3 (5)	0 (0)	3 (5)
Total	16 (27)	7 (11)	23 (38)

Interviews with non-participating low carbon energy developers:

In addition to the interviews with developers who held a CfD, 17 semi-structured telephone interviews were carried with developers of low carbon electricity projects in GB who do not have a CfD contract (either because of failure at auction or because they had not applied to the CfD scheme at all).

Table 2. Types of technologies covered by interviewed non-CfD developers

	ACT	Biomass and CHP	EfW and CHP	Hydro	Offshore	Onshore	Solar	Tidal Power
Number technologies covered by the 17 interviewed companies	2	5	2	1	4	9	10	2

Quantitative online survey with developers and private investors:

After the in-depth interviews a follow-up self-completion online survey was sent to developers to provide a standardised template for capturing detailed information to inform our estimates of costs of debt and equity for different technologies, and the minimum rate of return required to make a project viable (hurdle rates). This was sent to all 34 developer companies of CfD projects, achieving 20 responses in total, although with relatively high rates of non-response to certain questions. Respondents represented 15 separate CfD projects, because for some projects more than one member of the project’s consortium of developer firms responded.

Cost-effectiveness analysis:

This addressed the evaluation question “Does the CfD scheme represent good value for money?” The analysis compared outcomes of the current CfD scheme with a modelled counterfactual scenario of subsidising the same level of generation under the RO. The rationale for using a scenario whereby the RO continued as the counterfactual was primarily that it is reasonable to assume that if the CfD scheme had not been introduced then the RO would likely to have continued (rather than a “do nothing” scenario of no form of support). This approach to counterfactual comparison was taken in DECC’s pre-implementation Impact Assessment to estimate the Net Present Value of the CfD scheme.

The modelling required developing estimates of the cost to consumers per MWh of electricity produced, by each technology. This was used to compare overall support costs to a counterfactual scenario assuming the CfD scheme had not been introduced and the RO continued out to 2050. The BEIS Dynamic Dispatch Model (DDM) was used as the basis of this modelling work.

Stakeholder workshop:

Separate from the commissioned evaluation, BEIS held a stakeholder workshop in January 2019. This brought together 24 stakeholders including academics, industry, investors and trade associations to discuss whether the scheme had met its original objectives and if these objectives were still valid. Representatives from the Committee on Climate Change, Legal & General, Anaerobic Digestion and Bioresources Association, Technopolis, Energy Technologies Institute, RenewableUK, Citizens’ Advice, Aurora, Solar Trade Association, Copenhagen Economics, Burges Salmon, Renewable Energy Association, Frontier Economics, Baringa, SocGen, Low Carbon Contracts Company, National Grid ESO, KPMG, Element Energy, Vivid Economics, Energy UK were in attendance.

For nuclear projects, the experience of BEIS officials working on this policy area was used as evidence.

Limitations of data collected

When forming conclusions on the evidence gathered, the following limitations of the underlying data were taken into account:

Interviews with CfD developers:

Overall, respondents reflected a good range of most of the different types of technologies developed under AR1 and AR2. However, developers of CfD projects with Energy from Waste with CHP and Dedicated Biomass with CHP were not included due to non-response.

Interviews with developers of low carbon projects without a CfD:

It is not known how representative the 17 interviews with developers of low carbon electricity projects without a CfD are of the wider population of unsuccessful applicants, because data on the number and profile of unsuccessful applicants is kept confidential. In addition, the relatively small number of interviews included in this qualitative sample should not be considered statistically representative of the wider population of firms who develop low carbon electricity across GB.

Online survey:

There was a higher proportion of respondents representing offshore and onshore wind projects, and a relative under-representation of other technologies. There was a high rate of non-response to certain questions. Findings from the survey have been reported if the questions were answered by at least 50% of respondents. Some questions, for example around hurdle rates, received very few responses which was likely to be due to commercial sensitivity. Findings from these questions have not been included in the analysis.

Estimates of CfD scheme on cost reduction:

As with all modelling of future outcomes, there is a significant degree of uncertainty in the projections. This analysis has focused on estimating the changes in cost of supporting a fixed level of low carbon deployment under the two regimes. The level of deployment, and the mix of technologies deployed, has been held constant, in line with BEIS’s latest reference case. The magnitude of the savings under the CfD scheme would likely vary materially under a different level and mix of low carbon deployment.

Approach to quality assurance

Internally the CfD evaluation and PIR have been reviewed by analysts working on low carbon electricity, the Dynamic Dispatch Model and evaluation in the Energy and Security Analysis team as well as the head of Energy Evaluations. Policy officials in the Clean Electricity Directorate, including the Senior Responsible Owner have also reviewed both documents. External peer review of the CfD evaluation was undertaken by Professor Derek Bunn, with expertise of energy economics, and Dr Barbara Befani and Charles Michaelis both with expertise in theory-based evaluation. Where relevant to the first phase of the evaluation, all of the peer review comments have been addressed. Peer review comments relevant to future phases of the evaluation will be addressed in phases two and three of the CfD evaluation. The Hinkley Point C CfD review was given Senior Civil Service clearance.

3. To what extent have the policy objectives been achieved?

At the time the CfD was launched, its objectives were to:

ensure sufficient investment in sustainable low carbon technologies to put us on a path consistent with our 2020 renewables targets and our longer-term target to reduce carbon emissions by at least 80% of 1990 levels by 2050^{[footnote 19]}; and
maximise benefits and minimise cost to the economy as a whole and to taxpayers and consumers – maintaining affordable electricity bills while delivering the investment needed

Overall evidence suggests the policy objectives have been met. This view was supported by stakeholders who were interviewed as part of the CfD Evaluation and those who took part in the workshop. More information on the extent to which they have been met can be found in the CfD Phase 1 Evaluation report.

Low carbon projects

This PIR focuses on CfD AR1 and AR2. The results can be found here:

In total 5.48 GW of capacity was originally awarded (2.14 GW in AR1 and 3.35 GW in AR2)^{[footnote 20]}. The LCCC’s CfD Register^{[footnote 21]} estimates a combined generation capacity of 5.26 GW, equating to 96% of initially awarded capacity, is currently on track to be delivered (See Figure 1).

Out of the 38 CfD projects that have been awarded a CfD in these two allocation rounds, developers of seven projects either did not sign their offered contracts or their contracts have been terminated. In all cases, these were solar PV and bioenergy projects. Of these projects which did not go forward, all but one were projects with an initial estimated capacity below 50MW.

Whilst the capacity awarded in AR1 and AR2 will contribute around 1.3% to all electricity generation by 2020, based on the January 2019 CfD register, when all projects are operational this is estimated to increase to around 6% of the UK’s total electricity generation between 2025 and 2030.

Figure 1. All auctioned (AR1 and AR2) CfD projects, cumulative capacity and number of units (phased projects counted as multiple units) and their expected commissioning dates

Source: CfD Register. LCCC 25/01/2019

The first nuclear project in a generation is in the process of being built as a result of a bilateral CfD. The CfD provided the certainty needed for EDF and China General Nuclear Power Corporation (CGN) to finance the Hinkley Point C project. The offer of a CfD was also an important part of the negotiations between government and Hitachi with regards to the Wylfa Newydd project. Bilateral CfDs have only led to the development of one new nuclear project, although this will make up significant capacity when it is built. Bilateral CfDs have received criticism for not delivering value for money for the consumer, in comparison to the decreasing price of renewables.

Investment

Evidence suggests that the 15-year price stabilisation mechanism has contributed substantially to meeting the policy aim of increasing investor confidence. Stakeholders and developers interviewed reported that this provides more certainty over future revenue, reduces risks for investors, and leads to a lower cost of capital.

In recent years we have seen a slight shift towards more international utility backed developer companies investing in UK renewables development. This is primarily driven by the profile of offshore wind developers.

AR1 secured investment enabling deployment of 750MW of ‘Established Technologies’. Since ‘Established Technologies’ were last able to compete for CfDs in AR1, a small number of projects have come through without support, such as Clayhill solar PV farm in Milton Keynes which opened in 2017 and is considered the UK’s first subsidy-free solar PV farm. Some reports^{[footnote 22]} suggest the co-location of the site with a 6MW battery storage facility may have strengthened their business case. This will enable the owners to be eligible to bid for ancillary services from National Grid.

Low cost, low carbon projects

The strike prices for future offshore wind projects fell by around half between AR1 in 2015 and AR2 in 2017; in AR2 the lowest clearing price that two projects received was £57.50/MWh, compared to £114.39/MWh (2012 prices) in AR1. This reduction in prices for offshore wind was faster than historical or international trends, as evidenced in the CfD Evaluation Phase 1 report.^{[footnote 23]}

Consumer savings

Based on our modelling estimates, the CfD scheme will reduce the impact of low carbon projects’ deployment on consumer bills under all scenarios, as compared with the RO policy that preceded it.

The reduction in costs to the consumer due to the CfD projects auctioned in AR1 and AR2 is estimated at around £3 billion (in present value terms) in comparison with supporting the same projects under the RO. The scenarios tested produced upper and lower bound estimates of £1 billion and £4 billion respectively.

The lower support costs under the CfD regime are primarily driven by the lower hurdle rates assumed compared to under the RO. With projected future CfD projects (excluding nuclear and carbon capture and storage (CCS)) also included, the consumer cost savings of the CfD regime through to 2050 are estimated at around £9 billion compared to the RO scheme, with a range of £4 billion to £14 billion in the scenarios tested.

For further details see section 5 on Value for Money of the CfD Evaluation Report.

4. What were the original assumptions?

The July 2011 impact assessment^{[footnote 24]} reported that the expected economic impact of the CfD led to a more efficient allocation of risk among investors, consumers and government, by allocating risk to those parties best able to manage or control it. In particular, the CfD was intended to:

insulate investors in low carbon generation from fossil fuel price risk, which they are unable to control, thereby leading to a reduction in the cost of capital to investors relative to alternative support mechanisms and, in turn, reductions in the costs to society and consumers of securing this investment; but
maintain exposure to a fluctuating wholesale price for those technologies that are able to respond to this signal in their operational decisions

The original impact assessment can be found here: Contracts for Difference impact assessment (DECC0144). We advise caution with direct comparisons as the underlying assumptions used in the impact assessment are different from the assumptions used in the evaluation.

In the case of the nuclear power station at Hinkley Point C, it was decided to opt for a bilateral CfD. A large volume of work was necessary on the part of the developer to progress the first nuclear power project in a generation to the point where contracts were ready to be entered into and information could be provided to enable the government to perform a credible value-for-money assessment. While developers were prepared to accept the risk that if their final proposition did not give consumers value-for-money no CfD would be awarded, they were extremely unlikely to participate in a competitive auction. As for other low carbon energy technologies, a CfD was considered an effective way to provide certainty on the returns per unit of electricity. Without this certainty on the level of returns, it is unlikely that investors or developers would have taken on the risk of construction, completion and plant performance onto their balance sheet.

5. Were there any unintended consequences?

Overall the evidence suggests the scheme has met its initial aims, however, there are some outcomes which those interviewed perceived as unintended, or unexpected.

Pay-as-clear^{[footnote 25]} auction design and speculative bidding

There was little evidence to suggest that speculative bidding was widespread. However, the interview findings suggest that some developers perceived that two elements of scheme design, a) pay-as-clear bidding and b) a relatively weak Non-Delivery Disincentive (NDD) by international standards, have made speculative bidding feasible.

The pay-as-clear approach incentivises bidders to bid their lowest possible strike price, in comparison to pay-as-bid where bidders may try to anticipate the expected clearing price and include a margin in their bid. Pay-as-bid therefore has potential to increase the strategic complexity of the auction and could result in pushing up the price of all bids, and therefore the cost to the consumer.

The NDD aims to incentivise applications to be made only for projects likely to be delivered and meet their Milestone Delivery Date (MDD). The MDD is the date by which developers have to demonstrate that they have made substantial progress with their project and occurs 12 months after contract signature. The NDD provides for an exclusion from further application for the site of a project that was awarded a CfD where (i) the applicant in respect of that project failed to sign, or (ii) the CfD was terminated prior to, or due to, a failure to meet the MDD.

The exclusion applies for up to 24 months from the date of the CfD notification for that project and aims to exclude such sites from being used for an application for the next CfD allocation round. When the exclusion period was extended in 2016, there was no clear evidence of the need for further measures to strengthen the NDD. We will keep its ongoing efficacy under review in order to ensure that it operates most effectively and proportionately.

Impacts of the Milestone Delivery Date (MDD)

Procurement practices

The MDD is the date by which the Milestone Requirement (MR) must be satisfied. This is a requirement for developers to have made substantial progress with their project. The MDD occurs 12 months after project signature. Developers can satisfy the MR by either the 10% spend route (evidence that the developer has spent 10% or more of the total project pre-commissioning costs on the project) or the project commitments route (evidence of compliance with or fulfilment of the project commitments). The MDD is intentionally ambitious to ensure prompt delivery of projects which helps to achieve better value for money for consumers. Whilst ambitious, the MDD has been successfully met by most CfD developers.

However, developers of a variety of different projects suggested that 12 months is too short a window to demonstrate spending of 10% of total pre-commissioning project costs. Many developers indicated this led to a rush to spend money or sign contracts in the period approaching MDD. It was argued by some developers that this resulted in procurement practices that developers would not normally undertake, which were less cost-effective and potentially created risks in quality and timeliness of construction works delivered (for example by paying large sums for construction works in advance of its completion).

There were instances where developers felt that the MDD put them in a difficult position when negotiating contracts. For example, where the supplier knew the project was reaching the MDD, and time was running short, the supplier could charge higher prices as the developer was in a rush to get contracts agreed. This was reported by developers, but we do not have any direct evidence of this occurring in practice. It should also be noted that the MDD was met by the majority of developers.

Risk Assessment of Projects

Having been through the process in AR1, some offshore wind developers felt that the renewables industry was now aware of the challenges of spending 10% of total project pre-commissioning costs in 12 months and would plan in advance to condense work within this period. However, this meant that pre-development feasibility work, that would normally have been carried out in advance of putting a project forward for a CfD auction, could be being delayed, posing some construction risks and cost uncertainties.

If the 10% spend route for meeting the MR exposes developers to undue risks, they may consider the project commitments route as an alternative.

For further details, see section 3 on CfD scheme Delivery Processes in the CfD Evaluation Phase 1 main report.^{[footnote 26]}

Impacts of not re-running Pot 1

Since AR1 there has been no further allocation round for Pot 1 ‘Established Technologies’. Developers interviewed as part of the independent CfD Evaluation reported that the lack of further Pot 1 auctions led to a relative fall in investment in these technologies. Despite these reports, there has been some evidence of an emerging ‘subsidy free’ established renewables market, albeit limited at this stage, with Clayhill solar PV Farm in Milton Keynes opening in 2017 as the UK’s first subsidy-free solar PV farm. However, some reports^{[footnote 27]} suggest the co-location of the site with a 6MW battery storage facility may have strengthened their business case. This will enable the owners to be eligible to bid for ancillary services from National Grid ESO.

Furthermore, some developers felt that not re-running pot 1 could lead to promotion of Corporate Power Purchase Agreements (CPPAs). Some stakeholders felt that this may not be an equitable way of spreading the costs of renewables across wider consumers, reporting that onshore wind and solar PV developers may look for private deals to supply to industrial firms. Stakeholders stated that this could result in the cost of renewables being split between a smaller pool of customers. Whilst there was little evidence of CPPAs being common practice, it could be argued that consumers may still benefit from these contracts through lower wholesale prices and their contribution to decarbonising the electricity system.

For further details, see section 4 on CfD scheme Design Features in the CfD Evaluation Phase 1 main report.

CfD as a mechanism for supporting innovation

The CfD has contributed to the reduction in costs of certain low carbon technologies and reduced costs for consumers. However, some developers felt that there was a gap in subsidy provision to support commercialisation of newer emerging technologies, with the potential for greater cost reduction in the future, possibly undermining opportunities to secure even greater value for money in the longer term.

CfDs are allocated on a competitive process, helping to maximise value for money for consumers. Where appropriate, BEIS can deploy additional tools such as the use of minima capacity requirements in auctions to support specific technologies. Such use must be weighed against the impact on value for money and previous uses of maxima and minima have had to be compatible with EU State Aid rules.

For further details, see section 4 on CfD scheme Design Features in the CfD Evaluation Phase 1 main report.

6. Has the evidence identified any opportunities for reducing the burden on businesses?

The CfD is an opt-in scheme for low carbon project developers, therefore any opportunities to reduce burden on businesses would be around the information and guidance associated with the scheme.

Both successful and unsuccessful applicants interviewed as part of the CfD Evaluation found that information and guidance provided in advance of applying to the scheme was clear and sufficient.

In the application phase, some developers reported difficulties around requirements to demonstrate certain eligibility criteria. However, it was felt that this may have been a result of the learning curve between AR1 and AR2. Where developers had applied to both rounds, they felt the second allocation round was clearer as they knew what to expect.

Developers also reported that they considered 12-month Milestone Delivery Date (MDD) as too short to complete sufficient development work to demonstrate the necessary 10% spend. Smaller firms, which cannot pay for costs of initial development work until they reach Financial Close, can struggle to meet the required MDD spending target. For larger firms (e.g. offshore wind developers) challenges were more around the large scale of construction works required in the 12-month period and the administrative challenge of collating financial information to demonstrate 10% had been spent. Despite this perceived challenging milestone, many projects have been able to meet the target.

For further details see section 3 on CfD scheme Delivery Processes in the CfD Evaluation Phase 1 main report.

Recommendation

Evidence from interviews with developers, plus economic modelling, suggests that the introduction of the CfD scheme has supported cost reduction in low carbon technologies deployment and helped bring down the level of subsidies. A number of CfD scheme design features have played a role, including:

the certainty provided by the price stabilisation contract, which reduces risks for investors and costs of capital for developers
competitive pressure at auctions, which encourage lower strike price bids
the response from wider supply chains to the reduced levels of subsidy on offer, which encourages innovation and further cost reductions

Findings from this report corroborate other evidence received by BEIS that support the claim that the CfD is still required to deliver the level of low carbon technologies deployment required to meet our decarbonisation targets. Furthermore, signalling future CfD allocations gives developers and investors the certainty needed to develop a supply chain that ultimately benefits the UK consumer.

As situations change however, it is right that government considers how mechanisms should evolve to best meet the overall needs of the consumer. We will explore whether the current level of price insulation is optimal, and whether providing developers with price signals to react to market needs can reduce overall system costs. When considering this question, we will also consider the advances in the flexibility technologies and services that offer means for developers to meet system needs.

Question 4

Capacity Market

Accepted Answer

Post-Implementation Review title: The Capacity Market
PIR number: BEIS012(PIR)-22-RE
Original IA/RPC No: DECC0076/DECC0103/ DECC0151
Lead department or agency: BEIS
Other departments or agencies: N/A

Date: 22 July 2019
Type of regulation: Domestic
Type of review: Statutory
Date measure came into force: 31 July 2014
Recommendation: Keep
RPC opinion: N/A

Contact details for enquiries: simon.Dawes@beis.gov.uk

Summary

1. What were the policy objectives of the measure?

The Capacity Market (CM) has three objectives:

security of supply: to incentivise sufficient investment in capacity to ensure security of electricity supply
cost-effectiveness: to ensure the most efficient level of capacity is secured at minimum cost to consumers; and
avoiding unintended consequences: to minimise design risks and complement the decarbonisation agenda

In addition to the requirement to review the CM after five years contained in the Energy Act 2013, a near identical review requirement appears in the secondary legislation that implements the CM (The Electricity Capacity Regulations 2014). These Regulations require that the first five yearly review is published before 1 August 2019. A Five-Year Review of the CM was, therefore, published on 22 July 2019^{[footnote 28]}.

We have determined it proportionate to refer to the already published Five-Year Review of the CM for the purpose of fulfilling the Secretary of State’s obligation to review the CM under the Energy Act 2013. This cover sheet relies upon this earlier review publication, the findings of which remain accurate at the time of publication of this document.

2. What evidence has informed the PIR?

The review was carried out by BEIS officials through a Call for Evidence exercise held in August 2018^{[footnote 29]} and the collection of data from published sources such as the CM auction registers and relevant reports from National Grid, Ofgem and BEIS. For example, the evaluation of the transitional arrangement auctions^{[footnote 30]} and the Electricity Capacity Reports^{[footnote 31]}. Responses to the call for evidence were received from 83 stakeholders such as electricity generators/ developers, trade associations, interconnections, DSR providers and consultants^{[footnote 32]}.

3. To what extent have the policy objectives been achieved?

Overall the evidence suggests the CM’s policy objectives have been achieved, with some room for improvement going forward. The reliability standard for security of supply has been comfortably met. Auctions have been liquid, and the gross cost of the CM is at the lower end of the range predicted in the original IA. Whilst there have been some unintended consequences, amendments to the CM and other policies have been made to address these consequences as they emerged. Further incremental improvements are planned to ensure the CM continues to meet its objectives in future.

4. What were the original assumptions?

The September 2014 IA estimated that the change in net welfare of introducing a CM to be +£346m between 2012 and 2030 (£762m benefit from reducing unserved energy, £264m energy system costs, £41m institutional costs and £112m administrative costs). The net impact on the average annual domestic electricity bill was estimated at £2/year. Gross capacity revenues going to providers of capacity were estimated at between £0.7bn and £1.8bn per annum.

5. Were there any unintended consequences?

High numbers of diesel reciprocating engines won agreements in the early auctions leading to concerns about air quality impacts. BEIS worked with Ofgem, Defra and the Environment Agency to remove a loophole in environmental emission control regulations which addressed this distortion. BEIS also ensured that certain diesel engine operators were not being overcompensated by receiving funding through finance schemes in addition to the CM.

6. Has the evidence identified any opportunities for reducing the burden on business?

A broadly held view across respondents to the Call for Evidence was that the CM would benefit from simplification in a number of areas. For example, simplification of the Regulations and Rules, simplification of the prequalification process, greater clarity of information on stress events and greater clarity about the roles of delivery partners, BEIS and Ofgem. We are committed to considering the case for simplification.

7. For EU measures, how does the UK’s implementation compare with that in other EU member states in terms of costs to business?

N/A

The Capacity Market Review can be found here: ## Capacity Market: 5-year Review (2014 to 2019)^{[footnote 33]}

Question 5

Conflicts of Interest

Accepted Answer

Post-Implementation Review title: Energy Act 2013 Review Chapter 5 – Conflicts of Interest
PIR number: BEIS012(PIR)-22-RE
Original IA/RPC No: N/A
Lead department or agency: BEIS
Other departments or agencies: Ofgem

Date: 31 January 2019
Type of regulation: Domestic
Type of review: Statutory
Date measure came into force: 23 December 2013
Recommendation: Keep
RPC opinion: N/A

Contact details for enquiries: Renewable.Electricity.Correspondence@beis.gov.uk

Summary

1. What were the policy objectives of the measure?

The powers introduced by chapter 5 of the Energy Act 2013 were intended to mitigate potential conflicts of interest between National Grid’s delivery roles for Contracts for Difference (CfD) allocation and Capacity Market (CM) auctions, and their other regulated or commercial businesses. The regulations also allow the change of designated bodies for CfD or CM functions, and effect minor technical amendments to Energy Administration Orders. On the basis of this review and the evidence considered, these objectives remain appropriate.

2. What evidence has informed the PIR?

This is a low evidence review of the Conflicts of Interest chapter of the Energy Act. The review has been carried out by BEIS and has been informed by:

Consultation and responses on a more independent system operator (2018)^{[footnote 34]}
BEIS conversations (in person and by email) with National Grid and Ofgem staff
Discussions with BEIS policy teams for CfD and CM
Discussions with the BEIS shareholder team

A low evidence review was considered proportionate for this policy because the annual impact was estimated to be less than £5 million.

3. To what extent have the policy objectives been achieved?

Analysis suggests that the policy objectives have been met. The policy has been used to enable the Transmission licence to be modified allowing the following:

creation of a data handling facility to ensure commercially sensitive data is protected;
business separation of some functions to reduce the risk of conflicts of interest arising;
a duty on the National Grid Director responsible for EMR analysis to ensure that it is not unduly influenced for the benefit of their other interests;
restrictions on EMR information leaving the System Operator business; and
managerial, information, physical, employee and legal separation of certain competitive businesses that present potential conflicts of interest.

Government and Ofgem agreed that the ringfencing enforced through the above represented a comprehensive and reasonable response to the potential conflicts of interest identified.

The power to allow the change of designated bodies for CfD or CM functions has not yet been used but remains necessary.

4. What were the original assumptions?

A modification to National Grid’s Electricity Transmission Licence, Special Licence Condition 2N was laid before Parliament on 19 June 2014 and came into force on 1 August 2014. Special Condition 2N was drafted following publication in April 2013 of an assessment of the potential synergies and conflicts of interest arising as a result of National Grid Electricity Transmission plc (NGET) taking on the Electricity Market Reform (EMR) delivery role.

The power to allow the change of designated bodies for CfD or CM functions was considered necessary to respond to future changes in circumstances that might make those bodies unavailable, unsuitable or inefficient for the delivery of those functions. On the basis of this review and the evidence considered, these assumptions remain valid.

5. Were there any unintended consequences?

None. It was understood that the restrictions would increase the cost of National Grid undertaking its functions, but this effect was considered to be necessary in order to reassure the industry that no conflicts of interest would be allowed to arise.

6. Has the evidence identified any opportunities for reducing the burden on business?

Burden on business is negligible. Administrative costs of the licence conditions imposed are minimal and these are regulated by Ofgem as part of the electricity transmission price control.

The costs to business are negligible and the intervention was a defensive one to mitigate potential conflicts of interest arising out of National Grid’s EMR roles. No IA was deemed necessary.

The recent changes to a more independent electricity system operator (ESO) are not considered to have altered the case for the 2014 licence modifications but this will be kept under review by Ofgem (see Annexes B & C for more detail). If ESO separation from 1 April 2019 is found to be effective, then allowing certain information to flow more freely within the ESO (but not outside) may lead to efficiencies resulting in slightly reduced cost and increased effectiveness. In that case, these powers may be required to amend the ESO licence conditions.

7. For EU measures, how does the UK’s implementation compare with that in other EU member states in terms of costs to business?

Not applicable.

1. What were the policy objectives of the measure?

The powers introduced by chapter 5 of the Energy Act 2013 were intended to mitigate potential conflicts of interest between National Grid’s delivery roles for Contracts for Difference (CFD) allocation and Capacity Market (CM) auctions, and their other regulated or commercial businesses. The regulations allow the change of designated bodies for CfD or CM functions, and to effect minor technical amendments to Energy Administration Orders. On the basis of this review and the evidence considered, these objectives remain appropriate.

A modification to National Grid’s Electricity Transmission Licence, Special Licence Condition 2N was laid before Parliament on 19 June 2014 and came into force on 1 August 2014. Special Condition 2N was drafted following publication in April 2013 of an assessment of the potential synergies and conflicts of interest arising as a result of National Grid Electricity Transmission plc (NGET) taking on the Electricity Market Reform (EMR) delivery role. This report was followed by a public consultation published in October 2013 and the government’s response, published on 23 June 2014. These publications contained a package of mitigation measures to manage those conflicts.

In summary the measures sought to achieve the following.

Creation of a data handling facility within NGET to ensure that commercially sensitive data submitted to NGET is protected.
Business separation of some of the EMR functions within NGET and from the rest of NG’s businesses to reduce the risk of conflicts of interest arising between the EMR ‘administrative’ functions and NG’s other interests.
A duty on the NGET Director responsible for the EMR analytical function to ensure that the EMR analysis it supplies for the delivery plan has not been unduly influenced for the benefit of NG’s other interests.
Restrictions on EMR information leaving the System Operator business within NGET (SO) – to ensure that information the SO has access to through carrying out the EMR delivery role does not pass to other NGET staff.
Managerial, information, physical, employee, and legal separation of certain National Grid ‘competitive businesses’ from NGET, that present potential conflicts of interest with the EMR delivery role.

2. What evidence has informed this PIR?

This is a low evidence review of the Conflicts of Interest chapter of the Energy Act. The review has been carried out by BEIS and has been informed by the following.

Consultation and responses on a more independent system operator (2018)^{[footnote 35]}.
BEIS conversations (in person and by email) with National Grid and Ofgem staff.
Discussions with BEIS policy teams for CfD and CM.
Discussions with the BEIS shareholder team.

A low evidence review was considered proportionate for this policy because the annual impact was estimated to be less than £5 million.

3. To what extent have the policy objectives been achieved?

Analysis suggests that the policy objectives have been met. The policy has been used to enable the Transmission licence to be modified allowing the following:

creation of a data handling facility within National Grid to ensure commercially sensitive data is protected
business separation of some functions within National Grid to reduce the risk of conflicts of interest arising
a duty on the National Grid Director responsible for EMR analysis to ensure that it is not unduly influenced for the benefit of their other interests
restrictions on EMR information leaving the System Operator business; and
managerial, information, physical, employee and legal separation of certain competitive businesses within National Grid that present potential conflicts of interest

Government and Ofgem agreed that the ringfencing enforced through the above represented a comprehensive and reasonable response to the potential conflicts of interest identified.

The power to allow the change of designated bodies for CfD or CM functions has not yet been used but remains necessary.

Ofgem considers that special condition 2N, which was transferred to the ESO’s new transmission licence when ESO separation took effect on 1 April 2019, is still needed in the short term whilst it is observed how effective the ESO separation is. In the medium term it is more nuanced, and it is probable that aspects of special condition 2N may be unnecessary following ESO separation. There are some aspects of 2N that will be required indefinitely. Any future modifications to 2N could be made in the standard way Ofgem makes licence modifications, in accordance with section 11A of the Electricity Act under which the licensee has certain defined rights of appeal. Alternatively, the Energy Act powers may need to be used.

There have been a small number of data breaches with restricted data inadvertently shared outside NGET. These contravened NGET’s normal procedures as well as the EMR license condition. In each case NGET acted as soon as they became aware of the breach and initiated compliance audits thereafter. The auction bid stack ringfence is considered to be effective. Penalties for non-compliance under the transmission license are up to 10% of global turnover.

Responses from the Electricity System Operator’s consultation highlighted that:

With respect to the structure of the ESO, stakeholders generally agreed that increased separation of the ESO within the National Grid Group, with a separate licence for the transmission owner and system operator parts of the Group was a significant step forward. A key message from stakeholder responses was that the separation needed to be, and be perceived to be, as robust as possible.

There was widespread support for further separation between the ESO and electricity TO functions of National Grid and generally stakeholders felt that our suggested minimum standards for separation were a significant step forward in terms of independence of the ESO. Some stakeholders felt that in some areas stronger separation measures were appropriate. Stakeholders were also clear that the separation would need to be robust in order to address any actual or perceived conflicts, and that there needed to be a clear cultural shift within the ESO in order to facilitate this.

This evidence from Ofgem’s consultation in 2017 on the System Operator demonstrates that the industry continues to have concerns about potential conflicts of interest between National Grid’s different roles. It therefore remains valuable to have safeguards in place to ensure EMR commercial information remains ringfenced, even within a legally separate System Operator.

4. To what extent have the policy objectives been achieved?

A modification to National Grid’s Electricity Transmission Licence, Special Licence Condition 2N was laid before Parliament on 19 June 2014 and came into force on 1 August 2014. Special Condition 2N was drafted following publication in April 2013 of an assessment of the potential synergies and conflicts of interest arising as a result of National Grid Electricity Transmission plc (NGET) taking on the Electricity Market Reform (EMR) delivery role.

The power to allow the change of designated bodies for CfD or CM functions was considered necessary to respond to future changes in circumstances that might make those bodies unavailable, unsuitable or inefficient for the delivery of those functions.

On the basis of this review and the evidence considered, these assumptions remain valid.

5. Were there any unintended consequences?

None. It was understood that the restrictions would increase the cost of National Grid undertaking its functions, but this effect was considered to be necessary in order to reassure the industry that no conflicts of interest would be allowed to arise.

6. Has the evidence identified any opportunities for reducing the burden on business?

Burden on business is negligible. Administrative costs of the licence conditions imposed are minimal and these are regulated by Ofgem as part of the electricity transmission price control.

The costs to business are negligible and the intervention was a defensive one to mitigate potential conflicts of interest arising out of Grid’s EMR roles. No IA was deemed necessary.

The recent changes to a more independent electricity system operator (ESO) are not considered to have altered the case for the 2014 licence modifications but this will be kept under review by Ofgem (see Annexes B & C for more detail). If ESO separation from 1 April 2019 is found to be effective, then allowing certain information to flow more freely within the ESO (but not outside) may lead to efficiencies resulting in slightly reduced cost and increased effectiveness. In that case, these powers may be required to amend the ESO licence conditions. BEIS should meet at least annually with Ofgem to consider this question.

7. For EU measures, how does the UK’s implementation compare with that in other EU member states in terms of cost to business?

N/A

Recommendation

For the policy to be kept.

Question 6

Access to markets

Accepted Answer

Post-Implementation Review title: Energy Act 2013 Review Chapter 6 – Access to Markets
PIR number: BEIS012(PIR)-22-RE
Original IA/RPC No: DECC0156
Lead department or agency: BEIS
Other departments or agencies: N/A

Date: 22 February 2019
Type of regulation: Domestic
Type of review: Statutory
Date measure came into force: 23 December 2013
Recommendation: Keep
RPC opinion: N/A

Contact details for enquiries: Renewable.Electricity.Correspondence@beis.gov.uk

Summary

1. What were the policy objectives of the measure?

The changes introduced through chapter 6 of the Energy Act 2013 were intended to promote liquidity in the wholesale power market, allowing government to intervene if necessary, and to introduce a scheme to ensure that independent renewable electricity generators could access the market under Contracts for Difference (CFD) despite not having access to secure offtake arrangements for the electricity generated.

On the basis of this review and the evidence considered, these objectives remain appropriate.

2. What evidence has informed the PIR?

This is a low evidence review of Access to Markets policy. Justification for a low evidence review is that the liquidity powers have not been used and the access to markets powers have been used successfully in the implementation of the Offtaker of Last Resort (OLR) policy.

The review was carried out by BEIS officials using evidence from the following sources:

Evidence from CfD allocation rounds
State of Energy Market reports; and
Offtaker of Last Resort reports

3. To what extent have the policy objectives been achieved?

Overall the general policy objectives have been met as follows.

Improved market liquidity has promoted competition and increased the robustness of the Contracts for Difference reference prices, a crucial element of Electricity Market Reform (EMR) programme. The ‘Secure and Promote’ licence condition was introduced by Ofgem in 2014 under Electricity Act powers, which meant that these parallel Energy Act powers have not yet been required.

Action to improve the Power Purchase Agreement (PPA) market has made it easier for independent generators to develop projects and has improved the cost-effective delivery of EMR.

On the basis of the information provided by Ofgem, we consider that the Offtaker of Last Resort (OLR) is operating well and that no changes are required. It is designed carefully to be a last resort, so there have been no applications as yet under the scheme, as would be expected.

4. What were the original assumptions?

Liquidity in the GB electricity market was in a period of decline since 2001 and is lower than other energy and commodity markets, including a number of European electricity markets.

The government was committed to ensuring that the electricity market under EMR was open to independent generators, important for promoting innovation and competition and for ensuring least-cost decarbonisation.

5. Were there any unintended consequences?

None.

6. Has the evidence identified any opportunities for reducing the burden on business?

Burden on business is negligible.

7. For EU measures, how does the UK’s implementation compare with that in other EU member states in terms of costs to business?

N/A

1. What were the policy objectives of the measure?

The changes introduced through chapter 6 of the Energy Act 2013 were intended to promote liquidity in the wholesale power market, allowing government to intervene if necessary, and to introduce a scheme to ensure that independent renewable electricity generators could access the market under Contracts for Difference (CFD) despite not having access to secure offtake arrangements for the electricity generated.

2. What evidence has informed the PIR?

On the basis of this review and the evidence considered, these objectives remain appropriate.

This is a low evidence review of Access to Markets policy. Justification for a low evidence review is that the liquidity powers have not been used and the access to markets powers have been used successfully in the implementation of the Offtaker of Last Resort (OLR) policy.

The review was carried out by BEIS officials using evidence from the following sources.

3. To what extent have the policy objectives been achieved?

Overall the objectives have been met as follows:

Improved market liquidity has promoted competition and increased the robustness of the Contracts for Difference reference prices, a crucial element of Electricity Market Reform (EMR) programme.

The ‘Secure and Promote’ licence condition was introduced by Ofgem in 2014 under Electricity Act powers, which meant that parallel Energy Act powers have not yet been required.

Action to improve the Power Purchase Agreement (PPA) market has made it easier for independent generators to develop projects and has improved the cost-effective delivery of EMR.

In April 2013, DECC initiated a CfD market readiness project to help independent developers understand and prepare for the introduction of CfDs. This consisted of two working groups reporting to a steering board. The groups included large and small suppliers, independent generators, legal firms, lenders, and others active in the market. Their work complemented the rest of Electricity Market Reform Package, particularly the Offtaker of Last Resort mechanism which supports independent developers in finding a route to market under CFDs.

Working Group One: Sample contracts

The first group considered how power purchase agreement (PPA) contracts will need to change to complement CfDs. PPAs will need to look slightly different under CFDs, and the outputs of this group will help ensure that financiers are familiar with the structures before the first CFDs are entered into. This will also help to reduce costs for the first movers, which can be a significant barrier for smaller market participants.

Securing a PPA, or another route to market, is a vital step in developing and financing energy projects and facilitating this process should reduce barriers for smaller independent generators and help to encourage investment in the UK energy sector. These benefits would be particularly notable for early CfD projects and smaller projects, for which legal costs are a more significant proportion of their development costs. Sample power purchase agreement heads of terms.

Working Group 2: Code of practice

The second group developed a set of best practice guidelines for the PPA market. This included a description of the process for negotiating a PPA and what is expected from each party at each stage. The guidelines are intended to reduce barriers to entry for small independents and help them contribute to a healthier market. Best practice guidelines.

Offtaker of Last Resort

The OLR policy, which was given effect by the Power Purchase Agreement Scheme Regulations 2014 (“the Regulations”), ensures that eligible renewable generators have access to a ‘Backstop’ Power Purchase Agreement (“BPPA”) on specified terms with a credit-worthy Supplier (the offtaker) throughout the duration of their CFD. By ensuring a route-to-market for the generator’s output on known (albeit below-market) terms, the OLR makes lenders more comfortable accepting alternative routes-to-market for independent renewable projects, including shorter-term contracting strategies. This stimulates a wider market in offtake for independents and reduces the cost of investment in renewable electricity, boosts competition in offtake and lowers costs to consumers.

In the unlikely event that generators seek a BPPA, Ofgem is required to obtain bids from Suppliers to manage the contract to purchase power from the generator and the costs of the lowest bid would then be shared among all Suppliers (according to their share of the electricity market by a levelisation process). Should a Supplier be unable to meet their liabilities under the scheme (for example in the event of insolvency), any shortfall is covered by the remaining Suppliers through mutualisation provisions in the Regulations.

However, to reduce unnecessary administrative costs through the mutualisation of very small amounts, we included provisions in the Regulations for a floor below which mutualisation would not be triggered and Ofgem would carry the cost: the mutualisation lower limit.

Ofgem must provide to the Secretary of State such information in connection with the power purchase agreement scheme as the Secretary of State may require for the purposes of conducting the review. Ofgem published the third OLR annual report in December 2018 (in respect of the OLR year that ended on 31st March 2018) and the fourth OLR annual report in January 2020.

Ofgem introduced the ‘Secure and Promote’ licence condition in 2014 by placing an obligation on the large, vertically integrated electricity suppliers to trade with voluntary participation by smaller suppliers. The purpose was to promote liquidity, also to secure the move to trading on auction platforms that had occurred voluntarily prior to the intervention. With the licence modifications having been introduced under the Electricity Act, licensees had the opportunity to refer the matter to the CMA, or indeed to request a Judicial Review.

On the basis of the information provided by Ofgem, we consider that the scheme is operating well and that no changes are required. It is designed carefully to be a last resort, so there have been no applications as yet under the scheme, as would be expected.

4. What were the original assumptions?

Liquidity in the GB electricity market was in a period of decline since 2001 and is lower than other energy and commodity markets, including a number of European electricity markets. Ofgem’s Energy Supply Probe in 2008 found that low liquidity in the electricity market was a concern, particularly as a barrier to new entry into supply markets and a source of competitive disadvantage for independent suppliers.

The government was committed to ensuring that the electricity market under EMR was open to independent generators, important for promoting innovation and competition and for ensuring least-cost decarbonisation. A Call for Evidence in July 2012 showed it had become harder to secure viable long-term PPAs which are typically needed to secure funding. The OLR would ensure that generators with a CfD have a ‘backstop’ route to market at a specified discount to the market price.

On the basis of this review and the evidence considered, these assumptions remain appropriate.

5. Were there any unintended consequences?

No unintended consequences have been identified.

6. Has the evidence identified any opportunities for reducing the burden on business?

Burden on business is negligible.

The liquidity powers have not been used, so costs to business are negligible as the intervention was defensive. No IA was deemed necessary.

As intended and designed as a last resort, the OLR policy has not been used and there are no policy costs to be covered by licensed electricity suppliers. Administrative costs are minimal as the Ofgem team responsible for a pre-existing policy also administers the OLR. Ofgem estimates the cost of OLR to be half of one full-time equivalent staff member. The OLR was estimated to have a business impact of less than £5m as evidenced in the IA here: Electricity Market Reform – Offtaker of Last Resort impact assessment (DECC0156).

7. For EU measures, how does the UK’s implementation compare with that in other EU member states in terms of cost to business?

N/A

Recommendation

For the policy to be kept.

Question 7

The Renewables Obligation: Transitional Arrangements

Accepted Answer

Post-Implementation Review title: Review of the Energy Act 2013 – Part 2, Chapter 7 (Renewables Obligation transitional arrangements)
PIR number: BEIS012(PIR)-22-RE
Original IA/RPC No: DECC0086
Lead department or agency: BEIS
Other departments or agencies: Ofgem

Date: 1 March 2019
Type of regulation: Domestic
Type of review: Statutory
Date measure came into force: 18 December 2013
Recommendation: Keep
RPC opinion: N/A

Contact details for enquiries: RO@beis.gov.uk

Summary

1. What were the policy objectives of the measure?

The 2013 Act covered two measures relevant to the Renewables Obligation (RO) scheme. The first was the transition from the demand-led RO to the new competitive (and so better value for money), Contracts for Difference (CfD) support mechanism. The second was the provision of a framework for a certificate purchase scheme aimed at reducing the risk of volatility in the value of support in the final years of the RO.

2. What evidence has informed the PIR?

Views on how the transitional arrangement worked were sought from the BEIS team responsible for RO scheme policy and from the scheme’s administrator, the Office for Gas and Electricity Markets (Ofgem). Stakeholder responses to previous consultations on the closure of the RO were also taken into account. Statistics on the number of accreditations and accredited capacity were taken from Ofgem’s published reports.

3. To what extent have the policy objectives been achieved?

This review covers implementation of the 2013 Act in England and Wales only. The first policy objective has been met as the RO is now closed to all new applications in Great Britain. On the second objective to introduce a certificate purchase scheme in 2027, government intends to issue a call for evidence on the introduction of a certificate purchase scheme in due course.

4. What were the original assumptions?

The assumption was that closing the RO and moving to CfDs would make the development of low carbon generation cheaper for both investors and consumers (details are given in the PIR of the Contracts for Difference provisions in the Energy Act 2013). The transition arrangements aimed to give clarity to investors to allow investment to continue without interruption. The certificate purchase scheme was intended to reduce the risk of volatility in the final years of the RO.

5. Were there any unintended consequences?

Anecdotal evidence suggests that a small number of developers sped up their projects so that they completed in a shorter period than usual to accredit by the closure deadline. Although unintended, it was anticipated that this would occur. But the practical impacts were likely to be minimal as such projects would have been balanced by those that hit unexpected delays and failed to accredit in time.

6. Has the evidence identified any opportunities for reducing the burden on business?

No opportunities have been identified. The closure requirements were designed to be as light touch as possible, whilst requiring sufficient evidence to be submitted by applicants to ensure they complied with the stated criteria. Any measures to relax these requirements would have allowed ineligible projects to accredit and would have increased the overall cost of the RO.

7. For EU measures, how does the UK’s implementation compare with that in other EU member states in terms of costs to business?

N/A

1. What were the policy objectives of the measure?

Background on the operation of the Renewables Obligation (RO)

Until the introduction of the Contracts for Difference (CfD) support mechanism, the Renewables Obligation (RO) was the main financial mechanism by which government incentivised deployment of large-scale renewable electricity generation in the UK. It was set up to play a key role in keeping the UK on track to deliver its legally binding EU targets to produce 15% of UK energy, and 30% of UK electricity, from renewable sources by 2020.

The RO came into effect in 2002 in England, Wales and Scotland, and in 2005 in Northern Ireland. Originally, the scheme was due to end in 2027 across the UK but in April 2010 the end date was extended to 2037 in Great Britain. In Northern Ireland, it was extended in two stages, moving to 2033 in April 2010 and 2037 in May 2013.

The RO does not provide direct cash payments to renewable generators. Instead, it operates as a market-based mechanism through a system of tradable green certificates called “Renewables Obligation Certificates” (ROCs). It works by placing an obligation on UK electricity suppliers to present a certain number of ROCs to the Office of Gas and Electricity Markets (Ofgem), the administrator of the scheme, in respect of each megawatt hour of electricity supplied to customers during the obligation year.

Suppliers buy these ROCs from renewable generators (or traders). Generators obtain them free of charge from Ofgem in relation to the renewable electricity they generate. Generators sell their ROCs with or without the electricity generated. This allows them to receive a premium in addition to the wholesale price of their electricity. The value of a ROC is a matter for negotiation between generator and supplier/trader.

Suppliers present ROCs to Ofgem to demonstrate their compliance with the Obligation or make a payment per ROC into a buy-out fund. After Ofgem’s administration costs have been deducted, the money from the buy-out fund is recycled on a pro-rata basis to suppliers who presented ROCs. This encourages suppliers to choose ROCs over the buy-out fund. It is assumed that suppliers pass a proportion of the recycled buy-out fund payments back to the renewable generators. It is also assumed that the cost of the RO to suppliers is passed on to consumers through their energy bills.

An accredited station receives support for up to 20 or 25 years, depending on its accreditation date.

The scheme was very successful in bringing forward deployment, with UK-wide capacity increasing from 3.1GW in 2002 to 29.2GW in March 2017. 65.2TWh of renewable electricity was generated in 2016-17 under the RO, representing 22.2% of total UK electricity generation (compared to 1.8% in 2002).

Electricity Market Reform proposals for the RO

In the annual energy statement to Parliament on 27 July 2010^{[footnote 36]}, the Department of Energy and Climate Change’s Secretary of State announced that the government intended to publish a consultation document on electricity market reform to examine the reforms necessary to deliver secure, affordable and low carbon energy.

In December 2010, government launched a consultation on the reform proposals^{[footnote 37]}. One aspect was the transition from the demand-led RO to the new competitive (and so better value for money), Contracts for Difference (CfD) scheme.

The consultation explained that changes would need to be made to the RO to enable a transition to the new scheme. It recognised that investors were making decisions at that time on the basis of the current support available under the RO, and some had already committed to projects on the basis of the current support. They therefore needed clarity about when the new scheme would be introduced and how existing investment plans would be affected.

Following the consultation, government published a White Paper in July 2011^{[footnote 38]} setting out the preferred arrangements to ensure that the period of transition between the RO and CfD ran smoothly and allowed investment to continue without interruption. The key points were as follows:

The RO would close to new accreditations on 31 March 2017. No generation would be able to accredit under the RO from that date;
All support under the RO would cease by the existing end date of 31 March 2037;
Limited grace periods would extend the accreditation deadline in specific circumstances. These were aimed at protecting generators who were unable to meet the deadline due to factors beyond their control;
Provisions would be made for additional capacity to be added after 31 March 2017 (e.g. to allow for offshore wind phasing where operators accredited the total intended capacity of the wind farm by the deadline and registered uncompleted turbines so that they could be commissioned later);
To provide flexibility, new renewable generation would have a one-off choice between the RO and CfD for the period between the introduction of CfD in 2014 and the 31 March 2017 closure date of the RO;
To ensure ongoing stability of the RO, already accredited generation would continue to be supported under the RO and would not be permitted to transfer to CfD;
RO support for all technologies would be grandfathered^{[footnote 39]} at the rate applicable on 31 March 2017; and
In order to reduce the risk of volatility in the value of a ROC certificate in the final years of the RO, the obligation on electricity suppliers to submit ROCs would be replaced in 2027 by an obligation on an administrator to purchase certificates at a fixed price. The Technical Update published in December 2011^{[footnote 40]} proposed that the cost of purchasing the certificates should be funded by a levy on electricity suppliers in line with market share.

Following debates in the Houses of Parliament, the power to implement the details of the transition arrangements, via secondary legislation, were set out in Part 2, Chapter 7 of the Energy Act 2013. In summary, this chapter gave the power to:

Make a Renewables Obligation Closure Order. This would prevent ROCs from being issued under any RO Order (whether made by the Secretary of State or by Scottish Ministers) in respect of electricity generated after a specified date. Different closure dates could be specified for different cases or circumstances, and transitional provisions and savings could be made. The same powers were given to the Department for Enterprise, Trade and Investment in Northern Ireland (now the Department for the Economy) to amend corresponding legislation in relation to the Northern Ireland RO;
To set up a certificate purchase scheme. It gave the power to make an Order to impose an obligation on a purchasing body to purchase certificates which had been issued to generators in respect of renewable electricity. With the consent of the relevant Northern Ireland Department, the Secretary of State was given the power to put a similar obligation on a Northern Ireland purchasing body. The Act set out the basic framework for the scheme. Key points were that certificates were intended to be issued in place of ROCs and to be issued in similar circumstances, but the price at which the certificates were purchased by the purchasing body would be fixed. Different purchase prices could be set for different periods of time, and adjustments could be made for inflation. It made a provision for an Order to impose a levy, charged in respect of supplies of electricity.

2. What evidence has informed the PIR?

This is a medium evidence review of the power granted in the Energy Act 2013 to allow secondary legislation to be brought in to enable the RO to be closed, and a certificate purchase scheme to be set up.

The justification for a medium evidence review is that:

The total impact of the provisions is less than £50 million and a medium evidence review was considered proportionate;
The review of the measures to close the scheme will have no impact on the future operation of the RO scheme as it is now closed to new applications; and
The previous government had announced the intention to bring the certificate purchase scheme into force in 2027^{[footnote 41]}. It is too soon to conduct a review of the provisions for such a scheme.

The review was led by BEIS officials. Views on how the transitional arrangement had worked were sought from the BEIS team responsible for the policy of the RO scheme and from the scheme’s administrator, Ofgem. Statistics on the number of accreditations and accredited capacity were taken from Ofgem’s published reports. Stakeholder responses to the following previous consultations on the closure of the RO were also taken into account:

Transition from the Renewables Obligation to Contracts for Difference (July 2013)^{[footnote 42]};
RO grace periods consultation (Nov 2013)^{[footnote 43]};
Changes to financial support for solar PV. Part A: Controlling spending on large-scale solar PV within the Renewables Obligation (closure to over 5MW solar) (May 2014)^{[footnote 44]};
Further consultation on changes to financial support for solar PV. Part A: Introduction of a possible grid delay grace period under the Renewables Obligation (Oct 2014)^{[footnote 45]};
Changes to financial support for solar PV - Controlling spending on solar PV projects of 5MW and below within the Renewables Obligation (July 2015)^{[footnote 46]}.

The RO works on the basis of three complementary obligations: one covering England and Wales, and one each covering Scotland and Northern Ireland. This PIR looks only at the RO that BEIS is responsible for, that is, the RO for England and Wales.

The evidence relates to the period from 2013 up to the final closure of the RO in England and Wales to new applications on 31 January 2019.

3. To what extent have the policy objectives been achieved?

Summary

This review covers the implementation of the Energy Act 2013 in England and Wales only. The objective in the 2013 Act to close the scheme has been achieved as it is now closed to all new applications for accreditation. For certain projects in specific circumstances, exceptions extended the 31 March 2017 accreditation deadline up to 31 January 2019. This allowed developers who had made a significant commitment prior to the closure announcements to still come forward, whilst stopping excessive deployment and so protecting consumers, who fund the RO through their energy bills.

The 2013 Act also set out the basic framework for a certificate purchase scheme to come into effect in 2027. The government will engage with stakeholders on the scheme in due course.

Closure of the RO using powers conferred by the Energy Act 2013

Following the Energy Act 2013, the government launched a public consultation in July 2013^{[footnote 47]} setting out detailed proposals for the operation of the RO during the transition period from the introduction of CfD in 2014 to the closure of the RO to new capacity on 31 March 2017.

That was followed by a further consultation in November 2013^{[footnote 48]}, proposing detailed arrangements for the eligibility criteria and duration of grace periods. These allowed certain projects to gain accreditation under the RO after 31 March 2017.

The final details were set out in the Renewables Obligation Closure Order 2014^{[footnote 49]}. The grace periods relevant to England and Wales are set out in Ofgem’s guidance^{[footnote 50]}. Each grace period had strict eligibility requirements to ensure that only those projects the exception was intended to help would be able to make use of the exception.

Early closure of the RO to solar PV and onshore wind using powers conferred by the Energy Act 2013 and under the Energy Act 2016

As a separate measure to the EMR transition, a consultation was launched in May 2014^{[footnote 51]} to close the RO early to large-scale solar PV (over 5MW) in England and Wales. A subsequent consultation in October 2014^{[footnote 52]} focused on a proposal for an additional grace period. This was followed by a consultation in July 2015^{[footnote 53]} to close the RO early to small-scale solar PV (up to 5MW) in England and Wales. These measures were taken because solar PV was deploying much faster than previously expected, and the increased capacity under the RO would have significantly increased costs for consumers.

In May 2015, the previous government was elected with a manifesto commitment to end new subsidies for onshore wind and announced on 22 June 2015^{[footnote 54]} that the RO would close early to onshore wind in Great Britain. The technology had deployed successfully and was projected to meet the Electricity Market Reform Delivery Plan’s range of 11 to 13GW by 2020 that was needed to meet the UK’s 2020 renewable electricity generation objective, whilst remaining within the limits of what was affordable. Without early closure, there was a risk of deploying beyond this range, which would have added more costs to consumer bills or required a reduction in support for other renewables technologies. Following debates in the Houses of Parliament, a new Energy Act 2016 was introduced to implement that commitment.

As with the 2014 announcement of the closure of the RO, exceptions were made available for certain solar PV and onshore wind projects which extended the closure date by a year. The final details were set out in the Renewables Obligation Closure Order 2014 (as amended by the Renewables Obligation Closure (Amendment) Order 2015^{[footnote 55]} and 2016^{[footnote 56]}, and Part 5 of the Energy Act 2016^{[footnote 57]}:

The 2015 amendment was for solar PV above 5MW;
The 2016 amendment was for solar PV up to 5MW; and
Part 5 of the Energy Act 2016 was for onshore wind.

Solar PV and onshore wind grace periods

In England and Wales, solar PV above 5MW had three grace periods that all ran from 1 April 2015 to 31 March 2016. Similar grace periods for solar PV up to 5MW ran from 1 April 2016 to 31 March 2017. Onshore wind in England and Wales had five different grace periods that ran across different periods. The full details are set out in Ofgem’s guidance on solar PV above 5MW^{[footnote 58]}, solar PV up to 5MW^{[footnote 59]} and onshore wind^{[footnote 60]}.

The various grace periods can be summarised as follows:

Solar PV above 5MW:

Significant investment - April 2015 to April 2016
Grid delay - April 2015 to April 2016
Preliminary accreditation - April 2015 to April 2016

Solar PV up to 5MW:

Significant investment - April 2016 to April 2017
Grid delay - April 2016 to April 2017
Preliminary accreditation - April 2016 to April 2017

Onshore wind:

Approved development - May 2016 to April 2017
Grid and/or radar delay - May 2016 to June 2017
Approved development AND investment freezing - April 2017 to February 2018
Approved development AND grid and/or radar delay - April 2017 to April 2018
Approved development AND investment freezing AND grid and/or radar delay - February 2018 to February 2019

All technologies aprt from solar PV and onshore wind:

Grid or radar delay - April 2017 to April 2018
Investment Contracts - April 2017 to April 2018

ACTs and offshore wind:

Enabling Financial Decisions - April 2017 to April 2018

Dedicated biomass CHP:

Enabling financial decisions - April 2017 to October 2018

Dedicated biomass electricity-only:

Dedicated biomass cap - April 2017 to October 2018

Number of accredited stations and capacity each year

The graph below shows the number of new accreditations each year for stations in England and Wales up to 31 March 2017.

Data as at 31 January 2019 from Ofgem’s accredited stations report^{[footnote 61]}.

The peak at the start of the scheme was due to stations accrediting on 1 April 2002, the day the RO come into force - 89% of the total stations for 2002/03 accredited on that day and just over half of these were landfill gas stations. The rise in accreditations from 2012/13 onwards in England, and from 2014/15 onwards in Wales, was due to an increase in solar PV stations. These peaked in 2014/15 in England and then declined in response to the early closure of the RO.

The chart below shows the total capacity of stations accredited in each year in England and Wales. The spikes in capacity in England were due to: fuelled technologies in the early years of the scheme; fuelled and offshore wind in 2010/11; and offshore and onshore wind and solar PV in 2012/13 to 2014/15.