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EMR: Shaping up for summer Electricity market reform transition Introduction Renewable electricity developers with generation due to come online between mid‑2014 and 31 March 2017 will face an important decision: stick with the tried and tested Renewables Obligation (the “RO”) or apply for one of the first Contracts for Difference (“CfDs”). Further detail on CfD terms and allocation procedure is expected in August. In advance of that and in light of recent Government announcements on EMR transitional arrangements and delivery, this briefing offers a snapshot view on where CfDs look likely to weigh in, as compared with the incumbent RO support mechanism. Focusing on the crucial transitional period in particular, topics covered include the key differences between the two mechanisms, initial thoughts on draft strike prices and the possible implications of an early introduction of a fixed‑price Renewable Obligation Certificate (“ROC”) regime (in 2017) on new and existing Power Purchase Agreements (“PPAs”). The final section of this briefing also provides an update on the Capacity Market, as the form of the key design proposals begin to emerge.
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UK: Energy Briefing July 2013
Contents Introduction 01RO Vs CfDS at a glance 02Frequently asked CfD transition questions
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Update on capacity market 09Conclusion – Keeping an eye on our figures
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Contacts 10Appendix: Timeline for RO to CfD Transition
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RO Vs CfDS at a glance RO CfD Available to:
New generating stations or additional capacity accredited by 31.03.2017 .
New generating stations. Additional capacity over 5MW, which can be metered/measured separately to original capacity.
Length of revenue stream:
20 years. 15 years.
Form of support payment:
Revenue from tradable certificates.
Cash payments. No cost/risk equivalent to carrying/selling ROCs.
Timing of award Post‑construction, at commissioning stage.
Pre‑construction, once development consents given and grid connection offer received .
Protection against price volatility
Power price: No protection, though generator‘s exposure dependent on PPA arrangements . ROC price: Fixed‑price ROC regime to be introduced in 2027 (or 2017, depending on consultation outcome) .
Provides some protection for generator against power price volatility by topping price up from reference price to strike price . If reference price higher than strike price, generator must pay counterparty body the difference.
Protection against changes in law (CiL)
No regulatory CiL provision equivalent to the one proposed for the CfD. Two main ways in which RO accredited generator may be compensated following CiL: negotiated CiL clause in PPA, or increases in wholesale power price.
CfD terms provide protection to both generator and counterparty body from specific CiL . Compensation via strike price adjustments, in accordance with a formula (yet to be announced). Generator may be able to get additional CiL protection via PPA.
Revenue indexation
RPI CPI
Route to market Suppliers incentivised to offer PPAs to renewable generators, to obtain ROCs. Upon implementation of fixed ROC regime , suppliers will not be obliged to procure ROCs .
No obligation for suppliers to enter into PPA with independent generators . Proposed amendment to Energy Bill for regulations requiring suppliers to offer ‘backstop PPAs’, if deemed necessary .
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Frequently asked CfD transition questions Q: What is the timetable for transition? Between mid‑2014 and 31 March 2017, there will be a choice between the RO and a CfD for new generating capacity. Capacity already accredited under the RO will not be permitted to switch, subject to a limited exception for co‑fired biomass. From 1 April 2017 onwards, the RO will be closed to new accreditations (save for where grace periods apply). Existing projects will continue to run, with final RO contracts ending in 2037. A diagram depicting key events in the RO transition/CfD implementation timeline is provided at the end of this briefing. Grace periods will be in place in order to protect projects which narrowly miss the RO cut‑off date of 31 March 2017. The Government’s current ‘minded‑to’ position is to allow a 6 month period (i.e. until 30 September 2017) for generating capacity which fails to commission in time due to delays to grid connection or radar installation/upgrade. However, the RO Transition Consultation seeks views on possible alternative grace periods and conditions . Any capacity accredited within the grace period will be entitled to receive ROCs at the grandfathered rate, but the 20 year revenue stream will start running from the RO cut‑off date. Q: What are the arrangements for ‘vintaged’ RO projects? From 1 April 2017 until the end of the RO regime on 31 March 2037 (the “vintaged period”), it is likely that support levels will be fixed (grandfathered) at the ROC banding rates applicable on 31 March 2017. In addition, it is currently proposed that:
From the beginning of the vintaged period until 31 March 2027, the level of the obligation on suppliers to produce ROCs will be calculated on the basis of expected generation plus 10% extra ‘headroom’, to provide certainty over ROC income for this period. Suppliers continue to purchase ROCs.
From 1 April 2027 until the end of the vintaged period in 2037, a ʺfixed ROCʺ regime will be introduced. The Government intends to fix the ROC price at the 2027 buy‑out price plus 10% (as indexed). Under the fixed ROC arrangements, suppliers will not be under an obligation to purchase ROCs or pay a ‘buy‑out’ price. Instead, a statutory purchasing body (possibly Ofgem) will be legally obliged to purchase ROCs at a fixed price and levy suppliers for the cost, probably in accordance with market share. The detail of the fixed ROC regime will not be consulted on until next spring. However, early indications are that suppliers will still be free to purchase ROCs (in order to sell on to the purchasing body) but will not be required to by law .
In the July 2013 ‘Consultation on the Transition from the Renewables Obligation to Contracts for Difference’ , the Government announced that it is considering the case for implementing the fixed ROC regime in 2017, ten years earlier than originally proposed. The Government has asked for consultation responses from industry participants on the likely effects of the proposal on their projects and the PPA market. The next question considers this point. Q: What is the likely impact of the fixed ROC regime on new and existing PPAs for RO projects? New PPAs As the final detail for the transitional process has not yet been finalised, it would be prudent for generators and suppliers (or other offtakers) entering into PPAs in the
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Watson, Farley & Williams July 2013
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In Great Britain only. CfDs will be available in Northern Ireland from 2016.
14 https://www.gov.uk/ government/uploads/ system/uploads/attachment _data/file/223489/ ROtransitionconsultation 17July2013.pdf
15 See Annex C to the EMR Technical Update December 2011. https://www.gov.uk/ government/uploads/ system/uploads/attachment _data/file/48253/3884‑ planning‑electric‑future‑ technical‑update.pdf
16 See section 6 of the RO Transition Consultation in particular.
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As long as no CfD application made for same capacity (can accredit under RO if earlier CfD application unsuccessful).
2 As long as no RO application for made same capacity (preliminary accreditation permitted). Certain co‑fired biomass projects will be permitted to switch from RO to CfD, even after accreditation.
3 15 year period only starts running when generation commences.
4 Generators can buy protection from price volatility (e.g. a floor price) and other risks (e.g. intermittency risks and change in law) from suppliers via a PPA (or vertical integration).
5 See FAQs for more detail. Fixed price likely to be based on final ‘buy‑out’ price plus 10%.
6 There is a ‘basis risk’ of generators not being able to sell their power at the reference price. Also potential for leakage if PPA price not based on the same index(es) as the reference price. Some discount (e.g. cost‑reflective discount for balancing/weather risks under PPA) reflected in the strike price methodology.
7 As with the RO, protection against other risks can be bought from the supplier via a PPA (or vertical integration).
8 Changes that have discriminatory effects and/or limit generator’s ability to deliver output or receive appropriate payment and changes to certain network charges (relating to balancing costs and transmission losses).
9 In 2027 under current proposals, Government considering bringing it forward to 2017.
10 It is likely that suppliers will be permitted to continue to purchase ROCs and sell on to central purchasing body (see FAQ on PPAs).
11 Further announcements on PPA market expected (see FAQs).
12 https://www.gov.uk/ government/news/ energy‑bill‑amendment‑ to‑support‑independent‑ renewable‑generators
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RO Vs CfDS at a glance RO CfD Available to:
New generating stations or additional capacity accredited by 31.03.2017 .
New generating stations. Additional capacity over 5MW, which can be metered/measured separately to original capacity.
Length of revenue stream:
20 years. 15 years.
Form of support payment:
Revenue from tradable certificates.
Cash payments. No cost/risk equivalent to carrying/selling ROCs.
Timing of award Post‑construction, at commissioning stage.
Pre‑construction, once development consents given and grid connection offer received .
Protection against price volatility
Power price: No protection, though generator‘s exposure dependent on PPA arrangements . ROC price: Fixed‑price ROC regime to be introduced in 2027 (or 2017, depending on consultation outcome) .
Provides some protection for generator against power price volatility by topping price up from reference price to strike price . If reference price higher than strike price, generator must pay counterparty body the difference.
Protection against changes in law (CiL)
No regulatory CiL provision equivalent to the one proposed for the CfD. Two main ways in which RO accredited generator may be compensated following CiL: negotiated CiL clause in PPA, or increases in wholesale power price.
CfD terms provide protection to both generator and counterparty body from specific CiL . Compensation via strike price adjustments, in accordance with a formula (yet to be announced). Generator may be able to get additional CiL protection via PPA.
Revenue indexation
RPI CPI
Route to market Suppliers incentivised to offer PPAs to renewable generators, to obtain ROCs. Upon implementation of fixed ROC regime , suppliers will not be obliged to procure ROCs .
No obligation for suppliers to enter into PPA with independent generators . Proposed amendment to Energy Bill for regulations requiring suppliers to offer ‘backstop PPAs’, if deemed necessary .
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Frequently asked CfD transition questions Q: What is the timetable for transition? Between mid‑2014 and 31 March 2017, there will be a choice between the RO and a CfD for new generating capacity. Capacity already accredited under the RO will not be permitted to switch, subject to a limited exception for co‑fired biomass. From 1 April 2017 onwards, the RO will be closed to new accreditations (save for where grace periods apply). Existing projects will continue to run, with final RO contracts ending in 2037. A diagram depicting key events in the RO transition/CfD implementation timeline is provided at the end of this briefing. Grace periods will be in place in order to protect projects which narrowly miss the RO cut‑off date of 31 March 2017. The Government’s current ‘minded‑to’ position is to allow a 6 month period (i.e. until 30 September 2017) for generating capacity which fails to commission in time due to delays to grid connection or radar installation/upgrade. However, the RO Transition Consultation seeks views on possible alternative grace periods and conditions . Any capacity accredited within the grace period will be entitled to receive ROCs at the grandfathered rate, but the 20 year revenue stream will start running from the RO cut‑off date. Q: What are the arrangements for ‘vintaged’ RO projects? From 1 April 2017 until the end of the RO regime on 31 March 2037 (the “vintaged period”), it is likely that support levels will be fixed (grandfathered) at the ROC banding rates applicable on 31 March 2017. In addition, it is currently proposed that:
From the beginning of the vintaged period until 31 March 2027, the level of the obligation on suppliers to produce ROCs will be calculated on the basis of expected generation plus 10% extra ‘headroom’, to provide certainty over ROC income for this period. Suppliers continue to purchase ROCs.
From 1 April 2027 until the end of the vintaged period in 2037, a ʺfixed ROCʺ regime will be introduced. The Government intends to fix the ROC price at the 2027 buy‑out price plus 10% (as indexed). Under the fixed ROC arrangements, suppliers will not be under an obligation to purchase ROCs or pay a ‘buy‑out’ price. Instead, a statutory purchasing body (possibly Ofgem) will be legally obliged to purchase ROCs at a fixed price and levy suppliers for the cost, probably in accordance with market share. The detail of the fixed ROC regime will not be consulted on until next spring. However, early indications are that suppliers will still be free to purchase ROCs (in order to sell on to the purchasing body) but will not be required to by law .
In the July 2013 ‘Consultation on the Transition from the Renewables Obligation to Contracts for Difference’ , the Government announced that it is considering the case for implementing the fixed ROC regime in 2017, ten years earlier than originally proposed. The Government has asked for consultation responses from industry participants on the likely effects of the proposal on their projects and the PPA market. The next question considers this point. Q: What is the likely impact of the fixed ROC regime on new and existing PPAs for RO projects? New PPAs As the final detail for the transitional process has not yet been finalised, it would be prudent for generators and suppliers (or other offtakers) entering into PPAs in the
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Watson, Farley & Williams July 2013
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In Great Britain only. CfDs will be available in Northern Ireland from 2016.
14 https://www.gov.uk/ government/uploads/ system/uploads/attachment _data/file/223489/ ROtransitionconsultation 17July2013.pdf
15 See Annex C to the EMR Technical Update December 2011. https://www.gov.uk/ government/uploads/ system/uploads/attachment _data/file/48253/3884‑ planning‑electric‑future‑ technical‑update.pdf
16 See section 6 of the RO Transition Consultation in particular.
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As long as no CfD application made for same capacity (can accredit under RO if earlier CfD application unsuccessful).
2 As long as no RO application for made same capacity (preliminary accreditation permitted). Certain co‑fired biomass projects will be permitted to switch from RO to CfD, even after accreditation.
3 15 year period only starts running when generation commences.
4 Generators can buy protection from price volatility (e.g. a floor price) and other risks (e.g. intermittency risks and change in law) from suppliers via a PPA (or vertical integration).
5 See FAQs for more detail. Fixed price likely to be based on final ‘buy‑out’ price plus 10%.
6 There is a ‘basis risk’ of generators not being able to sell their power at the reference price. Also potential for leakage if PPA price not based on the same index(es) as the reference price. Some discount (e.g. cost‑reflective discount for balancing/weather risks under PPA) reflected in the strike price methodology.
7 As with the RO, protection against other risks can be bought from the supplier via a PPA (or vertical integration).
8 Changes that have discriminatory effects and/or limit generator’s ability to deliver output or receive appropriate payment and changes to certain network charges (relating to balancing costs and transmission losses).
9 In 2027 under current proposals, Government considering bringing it forward to 2017.
10 It is likely that suppliers will be permitted to continue to purchase ROCs and sell on to central purchasing body (see FAQ on PPAs).
11 Further announcements on PPA market expected (see FAQs).
12 https://www.gov.uk/ government/news/ energy‑bill‑amendment‑ to‑support‑independent‑ renewable‑generators
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meantime to agree detailed arrangements for various potential regulatory outcomes, as part of the change in law provisions. Having considered how traditional ‘agreement to agree’ change in law arrangements would stand up in a fixed‑ROC world, some parties are already opting to identify and address specific foreseeable EMR‑related risks and benefits at the outset, when negotiating PPA terms. Whilst this process can be painful and the resulting provisions cumbersome, the extra time and expense dedicated now could transpire to be well worth it, if parties avoid lengthy and costly negotiations (with potential expert involvement) later on, as well as benefitting from reduced uncertainty in the meantime. It is likely that the fixed ROC regime will be implemented in a way which allows a secondary market in ROCs. On that basis, suppliers/offtakers may seek to continue to purchase ROCs under the PPA at the specified contract rate (based on the final buy‑out price) and then sell on to the central purchasing body at the fixed price (which, as mentioned above, is likely to be the final buy‑out price plus 10%). An alternative arrangement, which would achieve the same end, would be for the generator to sell the ROCs to the purchasing body but pay some or all of the surplus (over and above the PPA agreed rate) back to the supplier. Where PPAs entitle the generator to receive a proportion of any ROC recycle fund payment received by the supplier, arrangements for moving to the fixed ROC would need to consider how generators should be compensated when the recycle fund ceases to exist. In addition, it would be prudent for PPA change in law provisions to factor in the possibility of the Secretary of State exercising legislative ‘back‑stop’ powers, or making some other regulatory provision, to address PPA market concerns. Further Government announcements on measures to address PPA market concerns will be made “shortly” . As with all change in law provisions, parties will need to agree which side will bear the risk, or be permitted to keep the benefit, of a particular regulatory outcome. Existing PPAs If the fixed ROC regime implementation remains at the proposed 2027 date, it is unlikely that many existing PPAs will be affected. Indeed, this was part of the Government’s original thinking in setting the date. However, an earlier 2017 date could well trigger change in law provisions in a significant number of existing PPAs. These can be seen as falling into two categories: older PPAs which will not envisage EMR and those entered into within the last 3‑4 years, which may contain specific change of law provisions relating to RO transition, some of which may refer specifically to the implementation of a fixed ROC regime. In both cases, it will be necessary for parties to scrutinise any change in law (and any other relevant) PPA provisions in order to consider whether the ROC‑purchase arrangements can/should continue to operate in the same way under the fixed ROC regime. This may depend on whether suppliers will be permitted to continue to purchase ROCs (i.e. if there is a secondary market). As mentioned above, current proposals indicate that this will be possible. Change in law provisions for compensation payments and ‘agreements to agree’ may well also be triggered. Parties will want to assess the likely implications of the proposed policy on these arrangements. Q: How do the draft CfD strike prices compare to ROC banding rates for the same period? The Government’s stated aim is to set strike prices at a level which provides an incentive to generators equal to the RO rates, at least for the period when both schemes are
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available. At first glance, the strike price levels appear more generous than ROC banding rates for the same period. However, the higher rates need to be balanced against the fact that the 15 year revenue stream for the CfD is shorter than the RO revenue (of 20 years). The methodology for setting strike prices takes the differing contract lengths into account, as well as an assumed lower cost of financing for CfDs compared with RO accredited projects , and the CPI indexing of CfD payments, compared with RPI indexed ROC rates. It is also worth noting that, as with the methodology for setting ROC banding rates, the strike price methodology for setting strike prices takes into account discounts offered by generators to reflect suppliers taking on forecasting/balancing risks . There are differing views across economic consultants and the industry as to whether the various assumptions are accurate, particularly over whether strike prices have been set at a level high enough to make up for the shorter contract length. The conclusion is likely to vary from project to project, depending on the technology the target commissioning date and other project‑specific factors. When assessing strike prices for a particular project, it is important to bear in mind that the applicable rate is the rate for the CfD year in which the target commissioning date of the project falls, not the date of the initial CfD contract award . For example, an offshore wind project granted a CfD inNovember 2014 with of a target commissioning date of August 2017 will (on the basis of the current proposals,) receive the 2017/18 price of £140/MWh, not the 2014/15 price of £155/MWh. The current strike price projections are in draft form only. The draft prices announced on 28 June are currently under consultation, with final prices due to be announced by the end of 2013. Q: Will the strike prices vary according to location of the generating station? During the administrative price setting period (i.e. before price auctions are implemented), there will be a flat rate for each eligible technology (within a given CfD year) across the whole of Great Britain, subject to a couple of exceptions: The Government is considering offering higher strike prices for large scale renewable energy projects in the Scottish Islands , where particularly high transmission costs and other factors might otherwise prevent projects from going ahead. In its ‘Response to the Call for Evidence on Renewable Energy Trading’ , the Government announced that it remained open to the possibility of CfDs being available for renewable generation from outside the UK (e.g. Ireland) being available, though is not yet clear how this would interact with domestic strike prices and the budget constraints set by the Levy Control Framework. The intention is for the CfD regime to extend to Northern Ireland (the Capacity Market will not, due to the single electricity market in Ireland). As most aspects of Northern Irish energy policy is devolved to the Northern Irish Executive, the Northern Irish Department of Enterprise, Trade and Investment will determine whether UK strike prices should apply there, or whether different levels should be implemented. CfDs will be available in Northern Ireland from 2016.
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Watson, Farley & Williams July 2013
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Under which, in the event of a change in law, the parties will agree a way forward which puts both parties in as similar a position as possible to their respective positions under the PPA, seeking expert determination if such agreement cannot be reached.
18 Or a pre‑determined alternative rate.
19 See paragraph 24 of DECC’s July 2013 consultation on the draft Delivery Plan (the “Delivery Plan consultation”).
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The Government’s position is that CfDs will reduce risks, and hence cost of capital, overall.
21 Though, in the absence of a back‑stop PPA with regulated cost‑reflective discounts, CfD generators are arguably in a weaker bargaining position when negotiating discounts compared with their RO counterparts, who offer ROCs which suppliers are (until the introduction of a fixed ROC regime) incentivised to procure.
22 See paragraph 47 of the Delivery Plan consultation.
23 See paragraph 81 of the Delivery Plan Consultation.
24 https://www.gov.uk/ government/uploads/ system/uploads/attachment _data/file/210404/130627 _Response_to_Call_for_ Evidence_on_Renewable_ Energy_Trading_Final.pdf
04 05 UK: ENERGY BRIEFING UK: ENERGY BRIEFING
meantime to agree detailed arrangements for various potential regulatory outcomes, as part of the change in law provisions. Having considered how traditional ‘agreement to agree’ change in law arrangements would stand up in a fixed‑ROC world, some parties are already opting to identify and address specific foreseeable EMR‑related risks and benefits at the outset, when negotiating PPA terms. Whilst this process can be painful and the resulting provisions cumbersome, the extra time and expense dedicated now could transpire to be well worth it, if parties avoid lengthy and costly negotiations (with potential expert involvement) later on, as well as benefitting from reduced uncertainty in the meantime. It is likely that the fixed ROC regime will be implemented in a way which allows a secondary market in ROCs. On that basis, suppliers/offtakers may seek to continue to purchase ROCs under the PPA at the specified contract rate (based on the final buy‑out price) and then sell on to the central purchasing body at the fixed price (which, as mentioned above, is likely to be the final buy‑out price plus 10%). An alternative arrangement, which would achieve the same end, would be for the generator to sell the ROCs to the purchasing body but pay some or all of the surplus (over and above the PPA agreed rate) back to the supplier. Where PPAs entitle the generator to receive a proportion of any ROC recycle fund payment received by the supplier, arrangements for moving to the fixed ROC would need to consider how generators should be compensated when the recycle fund ceases to exist. In addition, it would be prudent for PPA change in law provisions to factor in the possibility of the Secretary of State exercising legislative ‘back‑stop’ powers, or making some other regulatory provision, to address PPA market concerns. Further Government announcements on measures to address PPA market concerns will be made “shortly” . As with all change in law provisions, parties will need to agree which side will bear the risk, or be permitted to keep the benefit, of a particular regulatory outcome. Existing PPAs If the fixed ROC regime implementation remains at the proposed 2027 date, it is unlikely that many existing PPAs will be affected. Indeed, this was part of the Government’s original thinking in setting the date. However, an earlier 2017 date could well trigger change in law provisions in a significant number of existing PPAs. These can be seen as falling into two categories: older PPAs which will not envisage EMR and those entered into within the last 3‑4 years, which may contain specific change of law provisions relating to RO transition, some of which may refer specifically to the implementation of a fixed ROC regime. In both cases, it will be necessary for parties to scrutinise any change in law (and any other relevant) PPA provisions in order to consider whether the ROC‑purchase arrangements can/should continue to operate in the same way under the fixed ROC regime. This may depend on whether suppliers will be permitted to continue to purchase ROCs (i.e. if there is a secondary market). As mentioned above, current proposals indicate that this will be possible. Change in law provisions for compensation payments and ‘agreements to agree’ may well also be triggered. Parties will want to assess the likely implications of the proposed policy on these arrangements. Q: How do the draft CfD strike prices compare to ROC banding rates for the same period? The Government’s stated aim is to set strike prices at a level which provides an incentive to generators equal to the RO rates, at least for the period when both schemes are
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available. At first glance, the strike price levels appear more generous than ROC banding rates for the same period. However, the higher rates need to be balanced against the fact that the 15 year revenue stream for the CfD is shorter than the RO revenue (of 20 years). The methodology for setting strike prices takes the differing contract lengths into account, as well as an assumed lower cost of financing for CfDs compared with RO accredited projects , and the CPI indexing of CfD payments, compared with RPI indexed ROC rates. It is also worth noting that, as with the methodology for setting ROC banding rates, the strike price methodology for setting strike prices takes into account discounts offered by generators to reflect suppliers taking on forecasting/balancing risks . There are differing views across economic consultants and the industry as to whether the various assumptions are accurate, particularly over whether strike prices have been set at a level high enough to make up for the shorter contract length. The conclusion is likely to vary from project to project, depending on the technology the target commissioning date and other project‑specific factors. When assessing strike prices for a particular project, it is important to bear in mind that the applicable rate is the rate for the CfD year in which the target commissioning date of the project falls, not the date of the initial CfD contract award . For example, an offshore wind project granted a CfD inNovember 2014 with of a target commissioning date of August 2017 will (on the basis of the current proposals,) receive the 2017/18 price of £140/MWh, not the 2014/15 price of £155/MWh. The current strike price projections are in draft form only. The draft prices announced on 28 June are currently under consultation, with final prices due to be announced by the end of 2013. Q: Will the strike prices vary according to location of the generating station? During the administrative price setting period (i.e. before price auctions are implemented), there will be a flat rate for each eligible technology (within a given CfD year) across the whole of Great Britain, subject to a couple of exceptions: The Government is considering offering higher strike prices for large scale renewable energy projects in the Scottish Islands , where particularly high transmission costs and other factors might otherwise prevent projects from going ahead. In its ‘Response to the Call for Evidence on Renewable Energy Trading’ , the Government announced that it remained open to the possibility of CfDs being available for renewable generation from outside the UK (e.g. Ireland) being available, though is not yet clear how this would interact with domestic strike prices and the budget constraints set by the Levy Control Framework. The intention is for the CfD regime to extend to Northern Ireland (the Capacity Market will not, due to the single electricity market in Ireland). As most aspects of Northern Irish energy policy is devolved to the Northern Irish Executive, the Northern Irish Department of Enterprise, Trade and Investment will determine whether UK strike prices should apply there, or whether different levels should be implemented. CfDs will be available in Northern Ireland from 2016.
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Watson, Farley & Williams July 2013
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Under which, in the event of a change in law, the parties will agree a way forward which puts both parties in as similar a position as possible to their respective positions under the PPA, seeking expert determination if such agreement cannot be reached.
18 Or a pre‑determined alternative rate.
19 See paragraph 24 of DECC’s July 2013 consultation on the draft Delivery Plan (the “Delivery Plan consultation”).
20
The Government’s position is that CfDs will reduce risks, and hence cost of capital, overall.
21 Though, in the absence of a back‑stop PPA with regulated cost‑reflective discounts, CfD generators are arguably in a weaker bargaining position when negotiating discounts compared with their RO counterparts, who offer ROCs which suppliers are (until the introduction of a fixed ROC regime) incentivised to procure.
22 See paragraph 47 of the Delivery Plan consultation.
23 See paragraph 81 of the Delivery Plan Consultation.
24 https://www.gov.uk/ government/uploads/ system/uploads/attachment _data/file/210404/130627 _Response_to_Call_for_ Evidence_on_Renewable_ Energy_Trading_Final.pdf
06 07 UK: ENERGY BRIEFING UK: ENERGY BRIEFING
Q: Can I make an RO application and switch to a CfD later on if my project is delayed beyond the RO cut‑off date? Broadly speaking, no. Once a generator makes a RO application, it will not be able to apply for CfD for the same generating capacity. There will, however, be a special exception for biomass co‑firing stations, which will be permitted to leave the RO regime and apply for a CfD as a full biomass conversion, even where full RO accreditation has been obtained. Generators will be permitted to switch to a CfD application if they have applied for or obtained preliminary RO accreditation only, or if they have applied for but not entered into an investment contract. A CfD application may be made for additional capacity over 5MW, even where the rest of the generating station is covered by a RO accreditation, as long as the capacity can be metered separately. However, the switch decision is one‑way only. All additional future capacity for the same station would only be eligible for CfD support. Where a generator has been unsuccessful in a CfD/investment contract application through no fault of its own, it will still be able to make a RO application, before the cut‑off date. This option will not be available if the generator voluntarily withdraws from the CfD application, or if it otherwise causes the CfD to be terminated. Offshore wind phasing Offshore wind developers are currently entitled to apply for separate RO accreditation for various stages of a project, with each phase (up to a maximum of 5 phases) being entitled to the full 20 years’ support from the date of its accreditation. Offshore projects with construction stages likely to straddle the RO cut‑off date, with some phases accredited before 31 March 2017 and some afterwards, will be given three options: a. register all remaining phases under the RO regime by the 2017 cut‑off date, even if
they have not yet been constructed (the 20 years would start running from registration so the revenue stream length would be reduce in respect of phases not yet commissioned);
b. register one or more of the phases due to be commissioned by the 2017 cut‑off date under the RO regime and apply for a CfD in relation to later phases; or
c. apply for a CfD in respect of all phases, as long as no RO application has been made in relation to any of those phases.
Q: How will the first CfDs be allocated? Further detail on CfD allocation and the application process is expected in August. The current allocation proposals are summarised below. The first CfDs will be allocated through an administrative application process, rather than by auction. The CfD Operational Framework published in December 2012 clarified that CfDs will be allocated on a first come, first served basis (rather than 6 monthly allocation rounds as proposed in May 2012) whilst there is sufficient ‘headroom’ in the budget, factoring in the Levy Control Framework. A change to allocation rounds may be introduced once there is, for example, less than 50% of the budget left unallocated. There will be a two‑stage CfD allocation process:
Eligible generating plant will be able to apply for a CfD at the pre‑construction stage (the Government has indicated that, for wind projects, this will be upon proof of
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development consent and an accepted grid connection offer). When making an application, the generator will be required to specify ‘delivery commitments’ such as a target date for commencing generation and a significant financial commitment within a period of time. The commitments will be part of the CfD terms.
The generator will be required to commission the project within a Target Commissioning Window (TCW) set by the Government and prescribed in the CfD. Projects failing to commission within the TCW will still be entitled to payments at the grandfathered rate, but the term will be reduced, as the 15 years will begin to run from the end of the TCW.
At the point of transition to competitive price setting (which could be as early as 2017), the allocation and price setting processes will essentially merge. Allocation will be decided by auctions (initially technology specific, but then progressing to technology neutral auctions once technologies and the market have sufficiently matured, from about 2020 onwards). Q: Will CfDs be available to all technologies covered by the RO regime? The “renewable technologies” for which proposed CfD strike prices have been issued broadly correspond to the categories of “eligible renewable sources” under the RO regime for which generators can currently be accredited and receive ROCs. The levels of subsidy under the RO regime are banded according to the type and size of renewable energy technology with different rates applicable to different renewable sources. Similarly, the draft CfD strike prices vary for alternative technologies according to a methodology based on factors such as the technology costs and the construction constraints associated with that technology as well as reflecting the Government’s policies and agendas. The draft Delivery Plan sets out the methodology used and the assumptions used in setting the draft strike prices for each technology. Whereas certain strike prices are flat over the period specified, in part, to incentivise generators and developers, other proposed strike prices are set to decline based on, amongst other factors, industry cost reductions over time. As mentioned above, the current CfD strike prices are only in draft form, the final prices are due to be announced by the end of this year. Where the Renewable Heat Incentive (RHI) is available to a technology, the developer will still be able to benefit from a CfD, but tariffs will be calculated to avoid over‑compensation. The RHI tariffs were consulted on in September 2012 and the Government response is pending . Generating capacity which is covered by a CfD/the RO regime will not be entitled to receive Capacity Market payments during the tenure of the CfD/RO revenue stream. Again, this is to avoid over‑compensation. There are several technologies which currently fall within the RO regime but which are not supported by CfDs; either by the Government setting a strike price or by the offer of bespoke negotiations. As set out in more detail below, the Government’s stated reasoning is either (i) strategic (in the case of biomass co‑firing plants, dedicated biomass and bioliquids) or (ii) practical (in the case of geopressure). Technologies excluded from CfD support i. Biomass Co‑firing: co‑firing plants (i.e. stations which co‑fire biomass along with fossil fuels) have been left out of the CfD regime. This reflects the Government’s preference for full unit or plant biomass conversions which it believes are more
27]
Watson, Farley & Williams July 2013
25
As long as no CfD application has been made in respect of that project.
26 https://www.gov.uk/government /uploads/system/uploads/ attachment_data/file/65635/ 7077‑electricity‑market‑reform‑annex‑a.pdf
27 https://www.gov.uk/ government/consultations/ renewable‑heat‑incentive‑ expanding‑the‑non‑ domestic‑scheme>
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06 07 UK: ENERGY BRIEFING UK: ENERGY BRIEFING
Q: Can I make an RO application and switch to a CfD later on if my project is delayed beyond the RO cut‑off date? Broadly speaking, no. Once a generator makes a RO application, it will not be able to apply for CfD for the same generating capacity. There will, however, be a special exception for biomass co‑firing stations, which will be permitted to leave the RO regime and apply for a CfD as a full biomass conversion, even where full RO accreditation has been obtained. Generators will be permitted to switch to a CfD application if they have applied for or obtained preliminary RO accreditation only, or if they have applied for but not entered into an investment contract. A CfD application may be made for additional capacity over 5MW, even where the rest of the generating station is covered by a RO accreditation, as long as the capacity can be metered separately. However, the switch decision is one‑way only. All additional future capacity for the same station would only be eligible for CfD support. Where a generator has been unsuccessful in a CfD/investment contract application through no fault of its own, it will still be able to make a RO application, before the cut‑off date. This option will not be available if the generator voluntarily withdraws from the CfD application, or if it otherwise causes the CfD to be terminated. Offshore wind phasing Offshore wind developers are currently entitled to apply for separate RO accreditation for various stages of a project, with each phase (up to a maximum of 5 phases) being entitled to the full 20 years’ support from the date of its accreditation. Offshore projects with construction stages likely to straddle the RO cut‑off date, with some phases accredited before 31 March 2017 and some afterwards, will be given three options: a. register all remaining phases under the RO regime by the 2017 cut‑off date, even if
they have not yet been constructed (the 20 years would start running from registration so the revenue stream length would be reduce in respect of phases not yet commissioned);
b. register one or more of the phases due to be commissioned by the 2017 cut‑off date under the RO regime and apply for a CfD in relation to later phases; or
c. apply for a CfD in respect of all phases, as long as no RO application has been made in relation to any of those phases.
Q: How will the first CfDs be allocated? Further detail on CfD allocation and the application process is expected in August. The current allocation proposals are summarised below. The first CfDs will be allocated through an administrative application process, rather than by auction. The CfD Operational Framework published in December 2012 clarified that CfDs will be allocated on a first come, first served basis (rather than 6 monthly allocation rounds as proposed in May 2012) whilst there is sufficient ‘headroom’ in the budget, factoring in the Levy Control Framework. A change to allocation rounds may be introduced once there is, for example, less than 50% of the budget left unallocated. There will be a two‑stage CfD allocation process:
Eligible generating plant will be able to apply for a CfD at the pre‑construction stage (the Government has indicated that, for wind projects, this will be upon proof of
25
26
development consent and an accepted grid connection offer). When making an application, the generator will be required to specify ‘delivery commitments’ such as a target date for commencing generation and a significant financial commitment within a period of time. The commitments will be part of the CfD terms.
The generator will be required to commission the project within a Target Commissioning Window (TCW) set by the Government and prescribed in the CfD. Projects failing to commission within the TCW will still be entitled to payments at the grandfathered rate, but the term will be reduced, as the 15 years will begin to run from the end of the TCW.
At the point of transition to competitive price setting (which could be as early as 2017), the allocation and price setting processes will essentially merge. Allocation will be decided by auctions (initially technology specific, but then progressing to technology neutral auctions once technologies and the market have sufficiently matured, from about 2020 onwards). Q: Will CfDs be available to all technologies covered by the RO regime? The “renewable technologies” for which proposed CfD strike prices have been issued broadly correspond to the categories of “eligible renewable sources” under the RO regime for which generators can currently be accredited and receive ROCs. The levels of subsidy under the RO regime are banded according to the type and size of renewable energy technology with different rates applicable to different renewable sources. Similarly, the draft CfD strike prices vary for alternative technologies according to a methodology based on factors such as the technology costs and the construction constraints associated with that technology as well as reflecting the Government’s policies and agendas. The draft Delivery Plan sets out the methodology used and the assumptions used in setting the draft strike prices for each technology. Whereas certain strike prices are flat over the period specified, in part, to incentivise generators and developers, other proposed strike prices are set to decline based on, amongst other factors, industry cost reductions over time. As mentioned above, the current CfD strike prices are only in draft form, the final prices are due to be announced by the end of this year. Where the Renewable Heat Incentive (RHI) is available to a technology, the developer will still be able to benefit from a CfD, but tariffs will be calculated to avoid over‑compensation. The RHI tariffs were consulted on in September 2012 and the Government response is pending . Generating capacity which is covered by a CfD/the RO regime will not be entitled to receive Capacity Market payments during the tenure of the CfD/RO revenue stream. Again, this is to avoid over‑compensation. There are several technologies which currently fall within the RO regime but which are not supported by CfDs; either by the Government setting a strike price or by the offer of bespoke negotiations. As set out in more detail below, the Government’s stated reasoning is either (i) strategic (in the case of biomass co‑firing plants, dedicated biomass and bioliquids) or (ii) practical (in the case of geopressure). Technologies excluded from CfD support i. Biomass Co‑firing: co‑firing plants (i.e. stations which co‑fire biomass along with fossil fuels) have been left out of the CfD regime. This reflects the Government’s preference for full unit or plant biomass conversions which it believes are more
27]
Watson, Farley & Williams July 2013
25
As long as no CfD application has been made in respect of that project.
26 https://www.gov.uk/government /uploads/system/uploads/ attachment_data/file/65635/ 7077‑electricity‑market‑reform‑annex‑a.pdf
27 https://www.gov.uk/ government/consultations/ renewable‑heat‑incentive‑ expanding‑the‑non‑ domestic‑scheme>
>
08 09 UK: ENERGY BRIEFING UK: ENERGY BRIEFING
sustainable and provide higher levels of renewable energy. ii. Dedicated Biomass: dedicated biomass, as was concluded in the UK Bioenergy
Strategy paper (published in April 2012 ), should be deliberately constrained due to the relatively high costs of carbon abatement and risks of technology “lock‑in”. There is therefore no CfD strike price for dedicated biomass without CHP.
iii. Standard Bioliquids: although bioliquids are eligible for ROCs under the RO regime, there is a supplier cap on the amount of bioliquids which can be supported. Advanced bioliquids are included under the strike price for ACT (Advanced Conversion Technologies) but no other bioliquids will receive CfD support. The Government has stressed the importance of bioliquids to the transport sector (which it considers has limited options for decarbonisation) and is therefore discouraging the use of bioliquids for other purposes, such as electricity generation .
iv. Geopressure: no strike price was issued for geopressure due to a lack of any current geopressure projects receiving support under the RO regime and the fact that this technology is still at an early developmental stage.
Changes to categories Whilst certain categories of technology such as onshore wind and solar PV remain constant in both the RO regime and the under the new CfD, the thresholds at which CfDs are available should be noted. For onshore wind, hydro, anaerobic digestion and solar PV, only projects above 5 MW will be eligible for CfDs as opposed to the current regime where small (but not micro) generators have the one‑off option, at the time of accreditation, to choose to receive support under either RO or small‑scale Feed‑in‑Tariff (FiT) schemes . Subject to any transitional arrangements, under the CfD, micro and small scale projects will only have the option of utilising the existing FiT regime. Early responses from commentators, particularly in the solar PV sector, indicate industry concern that this failure to include mid‑range projects in the CfDs will further stagnate an already faltering market where low feed‑in tariff rates have severely constrained projects resulting in a “bleak outlook” for sub 5 MW projects . In relation to smaller‑scale projects, it is noted that the Government has (in July 2013) proposed an amendment to the current Energy Bill, by which the Energy Act 2008 would be amended to empower the Secretary of State to raise the FiT capacity thresholds to a maximum of 10MW for community energy projects. The detailed thinking on how it will interact with the RO and CfD transition process has not yet been revealed.
28
29
30
31
32
Update on capacity market The Government recently announced its intention to run the first Capacity Market auction in late 2014 for delivery in the winter of 2018/19, subject to state aid clearance . Together with this announcement, the Government set out the design proposals intended to form the basis of the detailed legislation implementing the Capacity Market. Although providing a good indication of the likely design of the Capacity Market, it is acknowledged that the current design proposals (and the subsequent implementing legislation) may need to be refined prior to coming into force this time next year, and to this end will be subject to a public consultation in October. In summary, the key design proposals proposed by the Government are as follows.
Amount of Capacity: Ministers will decide the amount of capacity to be auctioned based on analysis from the System Operator of the amount needed to meet an enduring reliability standard. The reliability standard will be used to determine a demand curve prior to a Capacity Market auction. Although the starting point will be to contract for the capacity required to meet the reliability standard, if this proves too expensive, the demand curve will reflect the agreed trade‑off to be made between reliability and cost (and the conditions under which the amount of capacity contracted may deviate from the amount required to exactly meet the reliability standard). The proposed reliability standard and the methodology for determining the demand curve were published as part of the draft delivery plan earlier this month and are now subject to the consultation process . Eligibility and Auction: The proposed Capacity Market will be technology neutral and all existing and new forms of capacity will be eligible to participate (including demand side response), with the exception of capacity supported by CfDs, small scale FiTs, the RO or interconnected capacity. Although acknowledging that interconnected capacity will not be able to participate in the first auction in 2014, owing to the perceived potential benefits of interconnected capacity participating in the Capacity Market, the Government is continuing to work on a solution that would allow such capacity to participate in future auctions. Following a pre‑qualification stage (primarily to ensure that participants in the Capacity Market can deliver the capacity they offer), eligible capacity providers will be able to participate in competitive central pay‑as‑clear auctions run by the System Operator. The initial auction will take place four years ahead of delivery with a further auction taking place a year‑ahead. In general, existing plants will be limited to being “price takers” and will only be able to bid in the auction to a relatively low threshold, whereas in contrast, new plants will be able to participate as “price makers” and can bid any price into the auction up to an auction cap. Delivery: The successful bidders will be awarded capacity agreements pursuant to which they will receive payment in return for the commitment to provide capacity when required in the relevant delivery year. The capacity provider’s obligations will be load following. A failure to deliver capacity when required will result in a financial penalty on the capacity provider based on the value of lost load. Such penalties will be subject to a cap calculated as a multiple of the cost of new entry multiplied by the MW of capacity agreements held by the capacity provider.
33
34
Watson, Farley & Williams July 2013
28
https://www.gov.uk/ government/uploads/ system/uploads/ attachment_data/file /48337/5142‑bioenergy ‑strategy‑.pdf
29 See paragraph 77 of the Delivery Plan consultation.
30 For generating stations accredited on or after 1 April 2010 only.
31 Leonie Greene, Solar Trade Association.
32 https://www.gov.uk/ government/news/ more‑community‑ energy‑projects‑to‑ get‑support‑under‑ feed‑in‑tariffs
33
Published in DECC’s Electricity Market Reform: Capacity Market ‑ Detailed Design Proposals on 27 June 2013.
34 The proposed reliability standard provides a system security level of 99.97%, in other words, a loss of load expectation of 3 hours per year.
>
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08 09 UK: ENERGY BRIEFING UK: ENERGY BRIEFING
sustainable and provide higher levels of renewable energy. ii. Dedicated Biomass: dedicated biomass, as was concluded in the UK Bioenergy
Strategy paper (published in April 2012 ), should be deliberately constrained due to the relatively high costs of carbon abatement and risks of technology “lock‑in”. There is therefore no CfD strike price for dedicated biomass without CHP.
iii. Standard Bioliquids: although bioliquids are eligible for ROCs under the RO regime, there is a supplier cap on the amount of bioliquids which can be supported. Advanced bioliquids are included under the strike price for ACT (Advanced Conversion Technologies) but no other bioliquids will receive CfD support. The Government has stressed the importance of bioliquids to the transport sector (which it considers has limited options for decarbonisation) and is therefore discouraging the use of bioliquids for other purposes, such as electricity generation .
iv. Geopressure: no strike price was issued for geopressure due to a lack of any current geopressure projects receiving support under the RO regime and the fact that this technology is still at an early developmental stage.
Changes to categories Whilst certain categories of technology such as onshore wind and solar PV remain constant in both the RO regime and the under the new CfD, the thresholds at which CfDs are available should be noted. For onshore wind, hydro, anaerobic digestion and solar PV, only projects above 5 MW will be eligible for CfDs as opposed to the current regime where small (but not micro) generators have the one‑off option, at the time of accreditation, to choose to receive support under either RO or small‑scale Feed‑in‑Tariff (FiT) schemes . Subject to any transitional arrangements, under the CfD, micro and small scale projects will only have the option of utilising the existing FiT regime. Early responses from commentators, particularly in the solar PV sector, indicate industry concern that this failure to include mid‑range projects in the CfDs will further stagnate an already faltering market where low feed‑in tariff rates have severely constrained projects resulting in a “bleak outlook” for sub 5 MW projects . In relation to smaller‑scale projects, it is noted that the Government has (in July 2013) proposed an amendment to the current Energy Bill, by which the Energy Act 2008 would be amended to empower the Secretary of State to raise the FiT capacity thresholds to a maximum of 10MW for community energy projects. The detailed thinking on how it will interact with the RO and CfD transition process has not yet been revealed.
28
29
30
31
32
Update on capacity market The Government recently announced its intention to run the first Capacity Market auction in late 2014 for delivery in the winter of 2018/19, subject to state aid clearance . Together with this announcement, the Government set out the design proposals intended to form the basis of the detailed legislation implementing the Capacity Market. Although providing a good indication of the likely design of the Capacity Market, it is acknowledged that the current design proposals (and the subsequent implementing legislation) may need to be refined prior to coming into force this time next year, and to this end will be subject to a public consultation in October. In summary, the key design proposals proposed by the Government are as follows.
Amount of Capacity: Ministers will decide the amount of capacity to be auctioned based on analysis from the System Operator of the amount needed to meet an enduring reliability standard. The reliability standard will be used to determine a demand curve prior to a Capacity Market auction. Although the starting point will be to contract for the capacity required to meet the reliability standard, if this proves too expensive, the demand curve will reflect the agreed trade‑off to be made between reliability and cost (and the conditions under which the amount of capacity contracted may deviate from the amount required to exactly meet the reliability standard). The proposed reliability standard and the methodology for determining the demand curve were published as part of the draft delivery plan earlier this month and are now subject to the consultation process . Eligibility and Auction: The proposed Capacity Market will be technology neutral and all existing and new forms of capacity will be eligible to participate (including demand side response), with the exception of capacity supported by CfDs, small scale FiTs, the RO or interconnected capacity. Although acknowledging that interconnected capacity will not be able to participate in the first auction in 2014, owing to the perceived potential benefits of interconnected capacity participating in the Capacity Market, the Government is continuing to work on a solution that would allow such capacity to participate in future auctions. Following a pre‑qualification stage (primarily to ensure that participants in the Capacity Market can deliver the capacity they offer), eligible capacity providers will be able to participate in competitive central pay‑as‑clear auctions run by the System Operator. The initial auction will take place four years ahead of delivery with a further auction taking place a year‑ahead. In general, existing plants will be limited to being “price takers” and will only be able to bid in the auction to a relatively low threshold, whereas in contrast, new plants will be able to participate as “price makers” and can bid any price into the auction up to an auction cap. Delivery: The successful bidders will be awarded capacity agreements pursuant to which they will receive payment in return for the commitment to provide capacity when required in the relevant delivery year. The capacity provider’s obligations will be load following. A failure to deliver capacity when required will result in a financial penalty on the capacity provider based on the value of lost load. Such penalties will be subject to a cap calculated as a multiple of the cost of new entry multiplied by the MW of capacity agreements held by the capacity provider.
33
34
Watson, Farley & Williams July 2013
28
https://www.gov.uk/ government/uploads/ system/uploads/ attachment_data/file /48337/5142‑bioenergy ‑strategy‑.pdf
29 See paragraph 77 of the Delivery Plan consultation.
30 For generating stations accredited on or after 1 April 2010 only.
31 Leonie Greene, Solar Trade Association.
32 https://www.gov.uk/ government/news/ more‑community‑ energy‑projects‑to‑ get‑support‑under‑ feed‑in‑tariffs
33
Published in DECC’s Electricity Market Reform: Capacity Market ‑ Detailed Design Proposals on 27 June 2013.
34 The proposed reliability standard provides a system security level of 99.97%, in other words, a loss of load expectation of 3 hours per year.
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The length of capacity agreements is yet to be confirmed. However, the current proposal is that existing plants will have access to a one year capacity agreement, majorly refurbished plants will have access to a capacity agreement with a duration of up to three years and new plants will have access to a ten year (or potentially longer) capacity agreement.
Secondary Market: Subject to the System Operator’s consent (not to be unreasonably withheld), providers can physically trade their capacity obligations from a year ahead of the start of the delivery year and throughout delivery years, provided that the party taking on the obligation is eligible and doesn’t already hold obligations.
Payment: The cost of capacity agreements will be recovered from suppliers based on their share of peak demand.
Conclusion – Keeping an eye on our figures As we enter the final year‑long countdown to the first CfDs becoming available and the first capacity auctions in 2014, the hazy silhouette of EMR is finally firming up into something against which we can sensibly assess likely impacts on business plans and project documentation. Whilst the much sought after morsels of detail are still being drip‑fed by the Government, industry participants would be prudent to use the interim period before CfD terms are announced to digest draft strike prices; conduct a risk/benefit analysis of the available rates and application options for the transitional period; consider how the timetable of RO transition matches up with project lead times; and work through the implications of an early fixed ROC regime for existing and proposed PPAs and other documentation. Therefore, whilst the proof of the pudding will be in the eating, scrutinising the ingredients beforehand will at least allow us to reach an informed view as to what we are likely to be in for. Should you wish to discuss any of the matters raised in this briefing, please speak with a member of our team below, or your regular contact at Watson, Farley & Williams.
Evan Stergoulis Head of Energy London [email protected] +44 20 7814 8113
Sophie Yule Associate London [email protected] +44 20 3036 9817
James Dow Associate London [email protected] +44 20 7814 8206
Victoria Barkas Associate London [email protected] +44 20 7863 8913
Simon Alsey Associate London [email protected] +44 20 7814 8214
Charles July Partner London [email protected] +44 20 7814 8238
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. 100‑000‑2160 LON KW KW 02/08/2013
Contacts
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Appendix: Timeline for RO to CfD Transition
