On-site power solution risks

The heavily regulated nature of the electricity sector, the changing nature of this regulation, and the high degree of interdependency created between different parties can mean that the legal challenges associated with on-site power solutions can be underestimated.

In our experience, review of the following areas early on when assessing a project is key, and can save unwelcome surprises later.

Connection to the grid and “stranded asset” risk: for on-site generation/storage at any scale, the need to supplement on-site generation with electricity imported from the grid, charge battery storage and (in many cases) to export electricity to the grid – and ensuring robust physical and legal avenues for so doing are available - should be carefully considered at the outset.

As well as envisaging a situation where on-site generation/storage and consumption are happening as expected, as part of the risk analysis it is important to carefully contemplate what might happen over the lifetime of the relevant on-site generation/storage. For example:

• What happens if the on-site power solution does not function as expected?
• What happens if future consumption at the site reduces or increases from current levels/expectations?
• Where there is segregation of ownership/operation of the on-site power solution from the consumer , how will each party be able to react if the other does not comply with their contractual obligations or, in extremis, goes insolvent or abandons the contract? 

Generally, given the essential nature of electricity supply for the sorts of large-scale sites interested in on-site power solutions, the answer to such questions is that having a grid connection in place from the outset is essential - or at the very least optimal. Often the generator will also require a grid connection for the export of electricity, given concerns about route to market and/or asset stranding where the on-site consumer doesn’t commit to taking all electricity or in the event of a default by the on-site consumer. 

Assuming there is an existing grid connection agreement for the site, this conclusion leads to two further key questions:

• To what extent do the terms of this agreement allow for the proposed new on-site power solution to be connected and the relevant required export and import levels, and what are the risks under those terms in respect of future changes to the position?
• Which entity holds the benefit of the grid connection agreement (usually a site owner/occupier and usually a single entity) and will there be a need (i) to transfer this to a different party, and/or (ii) enter into separate “grid sharing” arrangements (contractual or by way of a jointly-owned “gridco” counterparty) such that more than one entity at the site can have some degree of legally robust reliance on the grid connection agreement despite it only being in one entity’s name? The need for “grid sharing” arises, for example, in the UK because the Distribution Network Operators who offer connections to their distribution systems will generally require a single counterparty and will not offer any step-in rights to third parties (i.e. a right for specified third parties to take over the connection agreement in certain default scenarios). Accordingly, if the grid connection agreement can only be held in the name of the site owner/occupier or the on-site generator (but not both) a solution is required to cover the risk of the grid connection agreement being terminated by the DNO for insolvency or breach by the relevant counterparty. In contrast, in jurisdictions where grid connection runs with the land such arrangements are not required.

If the terms of an existing grid connection are not suitable (or require modification of their terms), there will need to be dialogue with the relevant network company and the necessary changes agreed. The earlier this can be commenced (or at least the process, timescales and costs discussed) the better, as this can be a lengthy process and if the outcome is that a physical upgrade to the existing connection is required, then significant cost and lead times will be associated with the relevant construction works.

It is also often overlooked that in some jurisdictions connection agreements provide rights for network companies (known as “use it or lose it” rights) to remove consistently unused capacity (export and import). In Croatia, for example, the national transportation grid is undersized so grid connection agreements have tight deadlines for building the grid connection. If the deadline is missed, the grid connection must be applied for again. In Austria, on the other hand, renewable energy communities enjoy a simplified access to the grid and a reduced fee. In the context of significant scale generation/storage projects, with large capital expenditure requirements, and often non-recourse debt finance involved, these risks that exist in principle in most connection arrangements can take on heightened importance and therefore need to be scrutinised.

If there is no existing site grid connection but one will be required, then the regulated process for the application for and construction of a new grid connection will need to be completed. Depending on the connection works (and consequential wider grid reinforcement works) required, the costs and lead times of new connections can vary dramatically and can make or break the viability of introducing new on-site power solutions.

If a decision is taken to proceed without a grid connection being in place, then it should be appreciated that the timescales and costs associated with any future procurement of a connection to the grid down the line (for example following a termination of the on-site generation arrangements) will generally be uncertain.

Electricity sector regulation: It can be easily overlooked that there can be multiple regulated electricity sector activities being undertaken by on-site generation/storage projects. In the case of projects in the UK, for example, often each of the following separate regulated activities will be taking place (i) electricity generation(/storage), (ii) the distribution of electricity, and (iii) the supply of electricity. While structures can involve obtaining licence(s) (particularly for the generation/storage activity), the assumption often made is that all activities will be conducted on a “licence exempt” basis. This both reduces the regulatory burden and is often part and parcel of avoiding various costs associated with buying electricity imported from the grid. 

The usual way to achieve this in the UK is to meet the requirements of the “class exemptions” regime legislated for under the Electricity Act 1989 3 See the Electricity (Class Exemptions from the Requirement for a Licence) Order 2001 (as amended) (the “Class Exemptions Order”)   (with case-specific exemptions in principle also possible, but only commonly seen for generation). However, generally there is no process for obtaining “sign-off” from Ofgem or government of being within such a class exemption. Therefore, careful review of the structure and the relevant wording in the exemptions regime needs to be undertaken so that the relevant organisations can satisfy themselves (and relevant funders) of this. The UK Government is in the process of reviewing the “class exemptions” regime to ensure that it remains fit for purpose in light of the growth of distributed generation and renewables 4 https://www.gov.uk/government/consultations/exemptions-from-the-requirement-for-an-electricity-licence-call-for-evidence .  This review is also linked to the UK Government’s review of network charging to ensure that all market participants pay a fair share of policy and network costs.

In addition to this fundamental analysis of which electricity sector licence/regulatory exemptions are being relied upon, it is also prudent to scrutinise the contractual assurances between the parties in respect of remaining within the relevant regulatory requirements, including qualifying for the relevant exemptions. For the UK, the analysis is often most complex here in respect of electricity supply, where the party acquiring electricity can (through the way in which they use that electricity, in particular via resale rather than self-consumption) cause the party supplying them electricity to cease to be within their supply licence exemption.

In Poland, self-consumption does not require an electricity generation licence, as it does not constitute a commercial activity. If, however, the surplus electricity is sold to any third party (whether through the public grid or otherwise, including on-site), an electricity generation licence is generally required, unless the project falls under capacity exemptions (such as a renewable energy source below 0.5MW). 

There is no separate supply licence in Poland. However, where there is separation of ownership/operation of the on-site power solution and ownership of the wires from the consumer, the contractual set-up may be established as a power purchase agreement and the conveyance of electricity as distribution. This is because under Polish law, construction of private wires requires consent from the energy regulatory authority, which is very rarely given. If the wires are not treated as private, they will be treated as distribution grid, which consequently triggers the obligation to obtain a distribution licence. 

In addition, for large scale projects the potential relevance of the transparency obligations imposed by EU (and for the UK retained EU law) regulation on wholesale energy market integrity and transparency (known as REMIT) should be analysed.

Ongoing access to the relevant private wires: for on-site power solution projects, wires are generally needed to convey electricity from the project to the point of consumption and, assuming there is a grid connection, to also convey electricity to the point of export to the grid. Unless the project asset, the electricity consumer and the wires are all owned by the same entity, the relevant parties who do not control these wires therefore need to bear in mind the extent to which they can be assured of ongoing access. 

In a UK context these wires will very often be owned and operated on an unlicensed “private wire” basis.

In contrast, in Poland there is no distinction between private wires and public grid. There is only a direct line concept, which refers to a line connecting one power producer with one consumer (only two parties are involved). However, the construction of a direct line has to be approved by the Polish regulator and in practice such approval may only be granted, where there is no possibility for the customer to be connected to the transmission/distribution grid. In any other case, the electricity networks/wires can generally be considered as distribution/transmission grid and their operation requires a relevant licence.

In jurisdictions such as the UK where a private wire approach is often used, given the absence of the protections afforded when dealing with licensed network, appropriate remedies where the party with control of the wires simply fails to comply with its obligations (including in extremis in an abandonment or insolvency scenario) should be thought through. While of course financial remedies for breach will likely be an aspect of contractual arrangements, in practice in such a default scenario the non-defaulting party (be they consumer or generator) is likely to need the ability to continue to use these wires urgently and to be assured the wires will continue to be appropriately maintained and operated. In some scenarios, rights of “step-in” can therefore be provided for, whereby the relevant wires are “taken-over” by the non-defaulting party. However, to do this in a robust manner requires proper review and treatment of the necessary land rights, the position on insolvency, and in practice whether the relevant party has the practical desire/capability to take over the private wires in this way. For large scale private wire networks with numerous separate connected consumers, the feasibility of step-in can prove even more problematic. In such situations, an insolvency remote gridco structure might provide a solution by better insulating the relevant assets from the wider business risks associated with the generator or onsite offtaker.

Finally, for both those controlling private wire networks and those using private wire networks controlled by a third party, it is worth being aware that the often overlooked EU “third party access” regime applies in respect of unlicensed distribution networks. By way of example, as implemented in the UK, the practical impact of this is that end consumers can require private wire networks to allow third party suppliers access to supply them over the relevant private wire network (with the relevant private wire network operator’s charges for granting such access also being regulated). 

Network charges and green levies to support government subsidies: the avoidance of both network charges and green levies tends to be a key incentive for the use of on-site generation in certain jurisdictions. This generally makes it important that electricity which is generated and consumed on-site does not pass through a licensed supplier and is not metered as passing onto the licensed network (often the two things would go hand in hand) as these respectively would lead to the need for the licensed supplier to apply levies and network charges to the electricity supplied. 

However, the regulatory position on this has changed and/or is changing in a number of jurisdictions  as governments seek to control the ability to bypass network charges and thereby concentrate them on those consumers who are drawing electricity from the grid.  

For example, the German legislature has already introduced a number of changes in recent years to limit the avoidance of levies and charges by on-site power solution projects. Regulatory changes regarding incentives for on-site generation in Germany focused in the past on limiting the definition of distribution lines exempted from network charges and levies, and instead the possibilities for avoiding or reducing renewable energy surcharge and benefiting from energy tax exemptions rather than network charges. Similarly, in the UK changes are being implemented which reduce the avoided network charges and “embedded benefits” associated with shifting consumption on-site. In addition, at the time of writing it has been suggested that UK government is contemplating reducing the extent to which green subsidies are recovered through levies on electricity supplied via the grid - a knock-on impact of such an approach could well be a reduced differential between the cost of on-site generated electricity versus electricity supplied via the grid.

Power purchase: to the extent that the structure dictates that the person consuming the electricity is different from the person generating it, terms need to be agreed for purchase of electricity by the consuming entity. Depending on who has access to export on to the grid, and the licensing analysis discussed above, commonly this may involve either:

the consumer at the site purchasing all electricity generated and selling or “spilling” the amount they do not need onto the grid; or alternatively

the third party on-site generator selling a portion of electricity to the consumer and itself spilling the untaken portion onto the grid via sale to an offtaker.

The terms of the purchase of electricity which is consumed on-site vary enormously depending on the commercials of the relevant structure, but where the purchasing consumer is able to offer a long-term fixed or “floor” price on electricity on all or the bulk of the output this can represent a particularly “bankable” and attractive proposition to a third party generator (particularly as renewable subsidies for new projects cease to be widely available) and increase the possibility of attracting project finance debt to the project.

The terms of such purchase (generally under a Power Purchase Agreement (“PPA”)) tend to be bespoke in nature and require significant development and negotiation across a wide range of areas, including in respect of:

• The credit-worthiness of the purchasing organisation (and any parent company guarantee/credit support they may provide). As renewable subsidy diminishes in many jurisdictions long-term PPAs with purchasers with large scale energy needs and a good covenant strength are increasingly used to underpin bankable projects. Appropriate creditworthiness on the part of the purchasing organisation is of course, however, fundamental to this equation.
• Demand changes - Given power purchase in an on-site generation context will tend to be associated with commercial/industrial activities with their own set of potentially changing circumstances, the “what if” question of what happens under power purchase arrangements where such commercial activities/industrial activities at the site need to change (or even cease altogether) needs answering. This may for example lead to discussions over term, break clauses and the extent to which the power purchase arrangements can (or indeed must) be transferred to any purchaser of the relevant site/business. Similarly, the position at the end of life of the relevant arrangements or generation assets needs practical thought, given it is generally necessary to assume the site will need to be able to continue to operate (and be supplied with electricity) when such point in time is reached.
• Development and commissioning - Where PPAs or other relevant power purchase terms are entered into prior to the relevant generation being developed (as is often the case), the relevant conditions precedent, milestones and associated deadlines that apply ahead of commissioning of the generation facility will need scrutiny. These will generally include areas over which the generating entity has control (such as build and financing) to other areas where the purchasing entity may well have control (such as land rights and grid connection), and therefore which party takes responsibility for the relevant condition/milestone being fulfilled (and the consequences where milestones are not fulfilled) requires interrogation and documentation.
• Network access - As discussed above, responsibility for the wires and apparatus connecting the consumer to the power solution and (where relevant) connecting both to the point of connection to the grid is an important area. Further, and perhaps counterintuitively, a structure that preserves ongoing access to the grid even where the power purchase arrangements are terminated will often be of relevance, in order to provide the relevant on-site project with an ongoing route to market.Change in law - Changes to the agreement arising from change in law and the process for such changes being agreed/determined will require inclusion for PPAs spanning any significant length of time.
• Price - Pricing of electricity supplied under the power purchase arrangements – and any interface with the cost of electricity procured from the grid - will of course be a key term, including in respect of the risk of levels of generation/consumption being different to that forecast and the associated imbalance risk that may arise from this and the impact of “negative pricing” (where there is a cost associated with exporting electricity onto the grid). The approach will tend to vary depending on the nature and commercial drivers for the relevant project. Similarly, the position on transfer and the value of any renewable benefits/green attributes associated with electricity being purchased needs to be addressed.
• Corporate Policies - Large corporate power purchasers may also seek to include requirements for the relevant generator to comply with such corporate’s general corporate policies (e.g. anti-bribery etc) in much the same way as any other supplier of goods or services to the corporate will be expected to comply. However, the on-site generator will need to review such obligations very carefully especially in terms of whether it confers any hair-trigger termination rights. The position of the on-site generator is likely to differ from that of many general suppliers of goods and services. In particular, the sunk capital costs to be put at risk by the generator in building new generation – and the risk/consequences to the generator losing the PPA and having to operate via selling electricity to the grid or worse still being left with a stranded asset with no route to market for its electrical output at all.

Revenue stacking: “revenue stacking”, whereby on-site assets export and/or store electricity in a way that best takes advantage of the revenues available for generation/demand reduction during times of system need, is also increasing in popularity. It is sometimes achieved through active trading of electricity 5 In the UK, for example, a recent modification of the GB Balancing and Settlement Code (Mod P375) will allow onsite/behind the (boundary) meter assets to participate in the GB Balancing Mechanism through individual asset level metering systems that can be used in the GB electricity settlement process. Mod P375 is being billed as a “fundamental building block for future energy flexibility” given the increase in assets that sit behind the grid boundary point metering systems. sale to an electricity supplier under a single power purchase agreement. Howeve,this approach requires sophisticated operational oversight (often by intermediaries with wider portfolios of generation/storage) and does not yet tend to offer long term certainty on levels of revenue. It is therefore difficult to structure as the basis of a bankable proposition, at least for the purposes of a single asset project financing.

Planning permission: on-site power solutions are generally located on sites which are already used in an industrial/commercial context. However, this does not mean that the planning permission that exists in respect of the relevant site will allow for the proposed facility; a fact which we see can be overlooked given the “brownfield” nature of the site. Therefore, early due diligence of whether new planning permission, or an amendment to the existing planning permission, will be required for the envisaged generation/storage is advisable. In certain jurisdictions such as the UK, there are generation capacity thresholds (in the UK being 50 MW) that may require a different consent to be obtained and therefore this should be reviewed for larger installations.

Land rights: the land rights to be granted (and the ability/right of the relevant consumer, who may for example themselves be a leaseholder) must be analysed carefully in the context of the type and scale of on-site power solution project being contemplated. Where land rights are being provided by one party to another (for example by the relevant consumer to a third party generator) then the duration of these land rights (for example the term of any lease) will need to be long enough to cover the envisaged duration of the power arrangements. The permitted use under any lease will need to capture the full extent of the activities to be carried out and the rights granted under any easement will need to be drafted to cover the proposed construction, operation and on-going maintenance of the cables to be installed. In respect of the relevant private wire networks and points of connection concerned, then appropriate access rights require proper review and any mechanisms for “step-in” to provide access to private wire networks where the intended controlling party is failing to maintain/provide access needs to take account of the relevant land rights required.

The manner in which land rights must be established, and whether they can be transferred without the consent of the landowner or used as a security for project financing differs significantly from jurisdiction to jurisdiction. For example, in Austrian projects, several different kinds of land rights are available. What is more difficult is separating the ownership in the land from the ownership in the generation facilities if they are not mounted on the ground but on a building like for a roof-top PV plant.

Debt Financing: on-site generation projects can lend themselves to a wide range of debt financing products, including project finance and asset finance. This could be on a single asset or portfolio/warehouse basis. Funders, principally commercial banks but also other sources of debt such as institutional investors, have increasing risk appetite to finance portfolios of small and medium scale on-site generation projects both within a single jurisdiction and even internationally across a number of different jurisdiction, in particular across a range of European markets.

Many on-site power solution projects do not meet all of the many criteria typically required by senior lenders to enable a classic project financing. For example, such projects may not be completely ringfenced from other activities of the sponsors or site owner, lack long-term offtake or route to market arrangements which substantially remove electricity pricing risk or have significant stranded asset risk. For this reason many developers consider proceeding with construction of projects without project finance, and then seek to finance them on a portfolio basis once the projects are operational.

Finance Lease, Sale and Leaseback, and Operating Leases: the structures used for on-site power solutions projects may also use these approaches as a financing tool. However, the IFRS accounting treatment of these approaches and the legal treatment of sale and leaseback arrangements should be carefully considered at the outset. 

Other aid/support received in respect of the relevant site: finally, it is worth noting that it is not unusual for the sorts of large industrial sites often suited to on-site generation/storage projects benefit from unrelated forms of support. For particularly large/nationally significant sites, State aid may have been applied to support the site and, by way of example, certain categories of business categorised as “electricity intensive industries” (“EIIs”) qualify for relief from the usual levies on grid supplied electricity used to fund renewable energy schemes. Where such support has been/is being received, analysis on whether the reduced costs flowing from on-site generation in any way contaminates the conditions/eligibility for such support is prudent. 

For example, the French Government also subsidises self-consumption projects through tenders decided by the Minister for Energy and managed by the energy regulator. These can be divided into two groups: 

1. Small solar installations on buildings (<100 kWp) with self-consumption. These projects can benefit from a 20-year contract, with an investment premium paid for five years coupled with a feed-in tariff for the surplus injected into the grid.
2. Renewable electricity installations with a capacity between 100 kWp and 1 MWp, regardless of the technology used. These projects can benefit from calls for tenders in the form of a premium for the electricity produced (whether it is self-consumed or injected into the public grid) or a contract for difference. This support is currently structured to incentivise self-consumption. 6 https://www.cre.fr/Documents/Appels-d-offres/appel-d-offres-portant-sur-la-realisation-et-l-exploitation-d-installations-de-production-d-electricite-a-partir-d-energies-renouvelables-en-auto

Public bodies sometimes take part in their own self-consumption projects. For example, the city of Rennes created a company to sell the solar electricity produced on the roofs of its buildings, and seven sites equipped with photovoltaic panels and schools generated 120,000 kWh of electricity in 2018. 7 https://metropole.rennes.fr/photovoltaique-rennes-mise-sur-lautoconsommation-et-linvestissement-prive-et-associatif

In Austria renewable energy generation is usually subsidised by tenders for market premiums. However self-consumption projects can obtain aid in the form of investment subsidies. Such subsidies are always notified aid schemes under EU state aid rules and are available for PV, wind and renewable gas (including hydrogen). No such aids are granted for hydro power or biomass. However, as soil sealing is a major problem in Austria, self-consumption plants for photovoltaic can only be subsidised if they are mounted on existing buildings, already paved surface, landfills or railway tracks. In all other cases investors must make sure that the land used falls into a special zoning category for PV use.

In Poland, renewable energy and CHP generation is also subsidised (by feed-in tariffs, CfD tariffs and feed-in premiums), but this mostly refers to electricity exported to the grid. However, small CHP installations (i.e. below 1 MW) can obtain a subsidy (feed-in premium) for all generated electricity, regardless of whether it is exported to the grid, or self-consumed.