How will (URN 14D/114) affect solar?

Government subsidies regime proposed “shake-up” for large-scale solar asset builds in England and Wales


At present, for the installation of a >5MW solar installation in the UK, a developer, contractor and what may loosely be referred to as “funder” [1], collaborate together on the development, installation, transfer, (“DIT”), or the development, installation, operation and maintenance, (“DIOM”), according to the following phases:

(i) development phase
Whereby an SPV (project-vehicle or “Asset”) is incorporated (a limited liability partnership or a private company limited by shares), planning consent (usually conditional with a set of planning and pre-planning conditions) is issued usually by the local planning authority, a power purchase agreement (PPA) is set up (with fixed pricing for 5/10/15 years) and agreed with an end-user client in tripartite form (between: a licensed electricity supplier, a buyer e.g. an owner of large amounts of commercial retail space, and a Generator-seller) or in bipartite form (between: a licensed electricity supplier and a Generator-seller), a distribution network operator (DNO) connection offer with an agreement to connect an asset to the Grid is obtained and the deposit paid for the offer, and a binding exclusivity agreement or an option to lease agreement is executed with the landowner or building owner where the installation will be situated;
(ii) construction phase
whereby the Asset contracts with an engineering procurement and construction installer (“EPC”) of solar plants to carry out small-scale civil engineering works, and to install modules, inverters, substations with mechanical and electrical works, to the Grid.  The same or a different operation and maintenance (“O&M”) contractor will then be responsible under an O&M agreement, and in accordance with the O&M manuals from the EPC, for the operation of the solar plant for usually 20 years, at least, in the UK, with the actual lifetime of the modules being 10-20 years more than that in certain instances;
(iii) Operational Phase
whereby the Asset is sold to a funder and the funder employs an O&M contractor to operate and maintain the plant owned by the Asset-yield-co (DIT), or, the Asset having had early-stage investment by a funder (DIOM) then becomes a yield-co with revenues distributed as dividends post netting off of operational costs for e.g. an EPCM under a master service agreement and any other operational costs.
The above three phases culminate in the production of the two revenue streams of payment for the offtake from an operation solar plant, namely electricity payments and premium realised from sale of their the renewable obligations certificates (ROCs) they are issued from OfGEM relating to the amount of eligible renewable electricity they generate.  Following the 1st of April 2015 should the Department for Energy and Climate Change (“DECC”) propose, following the close of the consultation period on their proposal for change to the financial support regime for large-scale solar (URN 14D/114[2]) on >7 July 2014[3] on the future of large-scale solar that the Office for Gas and Electricity Markets (“OfGEM”), that the ROCs regime should end and contracts for difference should be issued as there is insufficient capacity in the Government’s Levy Exemption Framework to compensate suppliers who would usually receive an apportionment of the monies that OfGEM collects in the buy-out and late payment funds on a pro-rated basis according to the ROCs presented for solar plants, as, this portion of the renewable energy mix targeted by the UK Government in the UK by 2020 is estimated to reach long-term targets well ahead of target, by 1 April 2015.


The development phase and the operational phase will change. Instead of ROCs, a contract for difference (“CfD”) will be applied for under an open bidding process (for allocation of a CfD if all the criteria are met according to a competitive bidding process periodically with first applications for CfDs for solar capable of being made on 1 October this year) or sealed bid (where a Generator can submit a sealed bid with an alternative strike price a Generator would be content to receive where there may be a constraint process where rationing of CfDs takes place due to the national system operator not having adequate budget to issue a CfD in relation to an application in a given year[4] from the UK Government Operator Company (as yet, not backed by sovereign guarantee, and so if the vehicle defaults in payment, there will be limited recourse for an investor as against the counter-party to the contract-for-difference with a Generator-Asset-SPV). During the operational phase, the CfD will be maintained and all of its requirements will require to be upheld during the lifetime of the CfD, and as with securitisation financed transactions, there is a security trustee that can step-in and step-out following a cure period to allow any Generator-default preventing revenue stream to be rectified[5].


(a) What is a CfD?

Section 6(2) of the Energy Act 2013 defines this as a contract under which a supplier funds certain payments and as being a contract that the CfD Counterparty (incorporated under the Companies Act 2006/a public authority[6]) is required to enter into under the Act[7].

(b) What are the key points to be aware of in relation to a CfD? |

(i) CfDs versus ROCs

a. Change in Law[8]QCiL events or “Qualifying Changes in Law” have now been drafted into the generic terms and conditions for CfDs updated in April 2014 and have been designed to compensate a Generator in the event that a change of law is a material and unforeseeable change that uniquely targets specific technologies, individual projects or certain CfD holders as a group. The QCiL protection covers political decisions to shut a Generator down/general changes that have a discriminatory effect without any objective justification. The QCiL protection extends to changes in law that would limit a Generator’s ability to deliver exported electricity or to receive appropriate payment for delivered exported electricity. The QCiL compensation will provide protection against certain changes in network charges relating to balancing system payments and transmission loss.

b. Credit Support Documents – “Collateral” – This is referred to as “collateral” in the terms and conditions published in April and will not include parent company guarantees, and will include a letter of credit or equivalent on-demand liquid form of guaranteed payment security that, e.g. in the event that the issuer loses their credit rating or folds, can be replaced within five working days with an equivalent form of security[9]. Despite a request for a similar form of security to be provided by the CfD Counterparty, the counter from DECC was that the provisions in the legislation including the ability for the Secretary of State to replace the insolvency remote CfD Counterparty in the event of default[10] (limited/no measure to terminate for CfD Counterparty default under the terms and conditions).

c. Variability in wholesale electricity market price – The CfD when it is issued has the relevant strike price for the period within which it is issued attributed to it, which is £125/MWh for 2013-2014, and 2014-2015[11] (“Initial Strike Price”). This can be adjusted during the lifetime of the CfD in accordance with the General Terms and Conditions for CfDs (“GTAC”)[12]. The Net Payable Amount under the CfD Agreement is the price that the Generator under the CfD receives if the Net Payable Amount after all deductions is positive (“NPA”, but if the NPA is negative, any NPA will be repaid by the CfD Counterparty – see g. below). The “Market Reference Price” (being the Baseload/intermittent market reference price) is calculated by reference to a “ Calculation Season” (a six-month period from 1 April or 1 October during which the Baseload Market Reference Price is calculated: see condition 15.2 of GTAC for the formula expressed in MWh in respect of each Settlement Unit, relating to the Baseload forward season trading day price calculated in respect of a trading day, reference price sample period or where a fallback Baseload price applies, in relation to a Settlement Unit (as defined under the draft CfD Agreement as each, “half hour period in a day divided into half hour-long periods starting at 00:00 on such day”)). Where the Market Reference Price is higher than the Strike Price, the Generator pays the CfD Counterparty who in turn pays the Supplier, the difference between the two, and if lower, then the CfD Counterparty obtains the difference from the Supplier and pays the Generator such amount (or ‘top-up payment’). It is likely that OfGEM given its experience in the RO regime will guide the five yearly strike price calculation work however the drop to a strike price for solar projects allocated a CfD in £110/MWh will need to be modelled by funds and developers in terms of their cost-model to ascertain the degree of certainty that they can attribute to a NPA under the CfD. The aim of the payment regime is for the Generator to be paid close to the Market Reference Price so that it obtains a predictable and steady revenue stream for power.

d. Indexation – the Strike Price is fully indexed 100% to the Consumer Price Index throughout the entire Term (see i. below).

e. Less than forecast metered output/Capacity Adjustment – Developers will be able to have a limited amount of flexibility to adjust their target capacity for a plant, to a limited extent above or below the Installed Capacity Estimate due to a Relevant Construction Event (“RCE”) by means of a RCE notice (in part J of GTAC) which is defined as an event that the Generator acting to a Reasonable and Prudent Standard would not be aware at the application date and which renders the development/construction/installation/conversion/commissioning of a Facility uneconomic. This is to be welcomed by developers, who albeit with the RCE would have to have the director’s certify separately as to the truthfulness of the RCE notice, the capacity can be reduced, however under-estimation does not seem to have been provided for in the GTAC but the DECC guidance does mention this, which may again something that is discussed during this consultation period.

f. Availability – this is not a determining factor for payments which is to be welcomed[13], however the forecast availability will be considered as a part of the Generator (owner of the Asset) information in relation to a prospective plant for which a CfD is sought and so has some materiality as it is explicitly referred to within the GTAC and so is required to be submitted.

g. Conditions Precedent – These will be conditions prior to first payments being received under the CfD so that once standards in connection, metering, capacity installed, and contract payment/Collateral (credit support – see b. above) have been provided, then, payments will be able to flow (see i. below).

h. Developer Asset-Co (or Developer backed by Funder – Asset-Co) supply chain plan/development phase deliverables – General Project Commitments[14] will need to be submitted with applications for allocations together with broadly the same criteria as set out above for the Development Phase[15] (including a Directors Certificate that the Generator that owns the Asset e.g. Developer/Developer-Consortium with a funder, have financial resources for the total project spend (‘proof of funds’), evidence that the site for the plant is relatively unencumbered by third party property rights and where necessary easements/other rights have been/can be obtained, and all other consents for the installation of the PV plant have been obtained) as a part of the Project Commitments in the CfD Agreement, together with evidence of an EPC agreement (Construction Phase) and evidence of a framework (major kit) supply (“Material Equipment”) agreement and a binding purchase order for the Material Equipment (so modules, inverters, frames, switchgear). 300MW sized portfolios of solar assets being developed, require more sophisticated responses in terms of the supply chain plan to obtain Secretary of State approval for submission of the related application for allotment of related CfDs, and the related guidance[16].

i. Payment – If the Net Payable Amount (condition 23 of the GTAC[17]) is a negative number in the relevant billing cycle then the Generator pays the CfD Counterparty the absolute value of the Net Payable Amount within 10 working days; but, if positive, then within 28 calendar days (1 month), the CfD Counterparty will pay the Generator the Net Payable Amount to allow the CfD Counterparty to recover the same amount from the Supplier. The “pay when paid” configuration is confirmed in the most recent guidance, so that the CfD Counterparty has time to get funds from the supplier to cover any Net Payable Amount relating to any strike price adjustment, qualifying law change compensation (as well as any relevant true-up payment[18]).

j. Term – it is anticipated that each CfD will endure 15 years. This can be varied to the extent that a CfD Counterparty has can offer a CfD on certain specified terms, e.g. where the generic terms do not suit the funding structure, and bilateral negotiations to permit, e.g. sharing of refinancing gains – with an example in the DECC guidance being where a “…project is sufficiently expensive or important..[19]”. The DECC guidance goes on to cite that refinancing bespoke term negotiations may arise, “…[w]here the largest Generators are able to later negotiate cheaper financing following construction, bespoke contract terms may enable suppliers (and therefore consumers) to share the benefits of lower financing costs. ..”. As such, only those solar developers with aggregated large-scale portfolios of development Assets might be able to petition to negotiate such bespoke conditions where e.g. all parties have tier-1 ratings with the usual credit reference agencies. The DECC guidance goes on to provide that large projects may have refinancing clauses which might enable developers to be free to recycle capital, however the definition of what ‘large’ will entail will require to be further requested during this consultation period by relevant interested parties.

k. Force Majeure – will allow relief relate to events beyond a developer’s control (e.g. QCiL – see a. above), for example where a network operator is at fault.

l. Dispute Resolution – this allows for senior representatives, failing which expert determination, failing which LCIA[20] binding arbitration.

m. Termination – for events such as non-payment of the NPA despite a 20 business day cure period[21], credit support (Collateral) default, metering access termination event, or the finally installed capacity is lower than the required installed capacity (after the Start Date). In the consultation documents published, the reasoning behind no termination for the insolvency-remote Government backed CfD Counterparty is that it can be replaced by the Government if for any reason it defaults in its payments, or if the supplier defaults in its obligations to provide the NPA payments to the CfD Counterparty to on-pay to the Generator then it can be replaced (akin to the Government acting in a form of trustee-role during the Term of the CfD to ensure that no matter what, even if late, payment is still made to the Generator if due).

Bankability of Solar >5MW PV projects for a global investor
    • A key perceived benefit to ROCs are that they allow grandfathering of rights to projects after a change in the allocation regime. DECC have made clear that there will be no grandfathering post 1 April for sub-5MW plants, and the grace period for projects for which substantial expenditure has been made by developers will be welcomed by many developers looking to build out large-scale plants. The “grace period” applies to those Assets being developed that obtained preliminary accreditation from OfGEM on or before 13 May 2014 – and evidence of this preliminary accreditation must be sent to OfGEM by 31 March 2015, to allow such plants to be able to be energised post-1 April 2015, with the long-stop date for energisation of such plants (or extensions to subsisting plants that had preliminary accreditation at e.g. 1.4 ROCs for additional capacity to be built, on or before 13 May 2014) being 31 March 2016, with OfGEM’s underlying logic being that they perceive the build-rate in the solar sector to be relatively fast. After 1 April 2015, sub-5MW plants may be able to be accredited for ROCs if for some reason they are not accredited for receipt of feed-in-tariff payments.
    • Credit support documents are a requirement for the Asset-owning company during the operational phase of a solar plant, and so it is likely that LCs/on-demand bonds, provided and maintained for 15 year terms of the CfDs will mean that smaller-scale developers that cannot obtain such security at cheaper rates following aggregation of a portfolio, may merge with or become acquired by larger developers. As a result, M&A activity between larger developers keen to acquire smaller developers with a good pipeline may increase, as the larger developers, able to mechanise the CfD application process, and perhaps aggregate 300+MW portfolios with supply chain plans for Secretary of State approval, will be able to obtain the Collateral or credit support document at a better rate than the developer operating on a smaller-scale.
    • The Government in their 13 May 2014 consultation proposal paper[22] on changes to financial support to solar, perceives that introduction of split-degression for over 50kW feed-in-tariff accreditable installations in two separate bands: one for other than stand-alone, and one for stand-alone, will work well to increase the installation of building mounted solar, especially in their targeted commercial and industrial 250kW-500kW PV installation target range as these roof-mounted plants.
    • A supplier cap (also known as a compliance cap) operating by limiting the proportion of their annual renewables obligation that electricity suppliers can meet using ROCs issued for a specific technology has been rejected in principle at this time by DECC in their 13 May 2014 Consultation Paper due to uncertainty over ROCs payments over 2015-17, and the other alternative to early closure of ROCs, a capacity cap would limit the total amount of new solar PV capacity above 5MW that could be accredited for ROCs but would leave developers uncertain as to whether their projects would commission in time and so obtaining development or construction risk with no guarantee of any subsidy payment due to the cap might be a major issue for such developers. These two other options were both rejected in favour of termination of the renewable obligation certificate regime early given the rate of rapid deployment of large scale solar builds in England and Wales.
  • The 13 May 2014 Consultation Paper on changes to solar PV is inviting responses from now until 7 July 2014 in accordance with the questions outlined to the rear of that paper.
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