Sushma Maharaj, Partner at Lux Nova Partners, explores what’s next for UK distributed generation
Ofgem’s recent decision to enable the Electricity System Operator (ESO) to give Distribution Network Operators (DNOs) blanket instructions to disconnect an aggregate quantity of distributed generation capacity within their areas (without compensation to those generators affected albeit subject to the ESO creating a long term enduring solution) comes hot on the heels of its Targeted Charging Review decision which virtually removed embedded benefits for distributed generators. See article by Robert Tudway at Lux Nova “Emergency disconnection of distributed generators”. The removal, also, of renewable subsidies (specifically Feed In Tariffs and revenues from the sale of Renewable Obligation Certificates) received by distributed generators, begs the question – “What’s next for UK distributed generators?”. This question is particularly timely as we await the Government’s Energy White Paper which is set to detail the UK’s path to net zero greenhouse gas emissions by 2050.
The cutting of subsidies and the erosion of embedded benefits point towards a proliferation of corporate power purchase agreements (PPAs) in the UK power sector. This means companies whose businesses are not related to energy will increasingly procure the electricity they use directly from generators (instead of via PPAs with licensed electricity suppliers) - and especially as this would also allow them to meet their corporate sustainability goals. Distributed generators too, will want to enter into corporate PPAS and other route to market agreements, as this would increase their options to take their projects to financial close and optimise project revenues.
Distributed Generators’ Revenue Stream
The revenue stack of distributed generators usually comes from:-
the distributed generator’s sale of power either directly under a PPA with a licensed electricity supplier or into the wholesale power market;
subsidies (e.g. Feed-in Tariffs (“FITs”) under the Feed-in Tariff Scheme (“FIT Scheme”); Renewable Obligation Certificates (“ROCS”) under the UK Renewables Obligation scheme); difference payments under the Contract for Difference (“CFD”) Scheme; and capacity market payments under the UK Capacity Market Scheme);
embedded benefits, i.e. the distributed generator’s share of the costs saved by the licensed electricity supplier (as purchaser of power from the generator) as a result of the generator being directly connected to the electricity distribution network – including TNUoS charges on suppliers (known as the triad benefit) and balancing services use of system (BSUoS) charges. Embedded generators under 100 MW in size also avoid paying TNUoS charges which is a charge incurred by transmission connected generators; and
ancillary services to National Grid/System Operator – i.e. services which are provided by the generator to support the safe functioning of the electricity network – e.g. Short-Term Operating Reserve (STOR) or “standby power”, Firm Frequency Response (FFR) i.e. the provision of generation or demand reduction in response to drops in system frequency, or Fast Reserve i.e. so as to control frequency changes arising from sudden changes in generation or demand. Generators will receive availability payments regardless of whether they are called upon to provide the relevant ancillary service and utilisation payments when the relevant ancillary service is called upon.
Some alternative routes to market for Distributed Generators
Optimisation services agreement with licensed electricity supplier:
Usually a PPA between a distributed generator and licensed electricity supplier would provide for the sale of power by the generator to the licensed supplier for a percentage of the day-ahead or spot electricity price. However, under this type of arrangement, the generator gives the supplier control of its assets to be traded at the discretion of the supplier in the electricity forward market or the spot market and also to enter the generator’s asset into the Balancing Mechanism, the Capacity Market or to provide FFR services to NGESO. In other words, the generator appoints the licensed supplier to trade electricity from its plant in the electricity forward market so as to optimise revenues for the generator in return for which the generator pays (usually monthly) an “optimisation fee” to the supplier (i.e. a flat fee per trade or a percentage of the profit made on the trade). The generator provides availability forecasts in respect of the plant on e.g. a seasonal, monthly etc. basis taking into account a range of factors including operational parameters for the plant – e.g. environmental obligations, O&M manual requirements etc. The generator can decide that the supplier will always be able to despatch electricity from the plant or will only be able to despatch electricity from the plant at a specified floor price – this way the generator can ensure that revenues will cover plant operating costs, fuel costs, debt repayment and also be able to meet the investment rate of return for the project. The commercial deal struck between the parties will vary according to the supplier’s share of the market and risk appetite.
However, when negotiating these types of arrangements/agreements, the following key issues will need to be considered:
suitability of the generation technology to control by the supplier;
provisions to ensure that the generator has transparency in respect of the trades executed by the licensed supplier;
responsibility for installation and operation of the remote dispatch platform via which the supplier is able to dispatch the generator’s plant and parties’ liabilities in respect of connectivity failures;
failure by the licensed supplier to trade the generator’s plant in accordance with agreed parameters including price, operational restrictions, permissions, warranties etc. and compensation payable by licensed supplier to generator and/or termination rights for persistent breach. Such compensation regime would also need to be carved out of the parties’ “no liability for consequential losses” provision;
change in law risk – the parties will, following a change in law, want to amend the agreement so as to achieve the same overall balance of benefits, rights, liabilities, obligations, risks, costs and rewards which existed between the parties prior to the change in law. However, the generator might want the right to terminate if there is a change in law. For example, when the Capacity Market Scheme was suspended, the market price paid by electricity suppliers for power from reciprocating gas engines increased and many of those generators wanted the ability to terminate their contractual arrangements to take advantage of higher market prices. Again, much will depend on the supplier’s market share and risk appetite; and
termination and termination payments – termination payments and caps and whether payments by a generator to unwind forward trades would be enforced if the supplier is in breach of its provisions under the agreement.
The distributed generator can further optimise its revenues by joining a cluster of distributed generation installations (e.g. wind turbines, photovoltaic power plants, small hydro etc.) and any other power sources in its local area to form a Virtual Power Plant (which is controlled by a central control entity or Virtual Lead Party via an information communication technology (ICT) structure). The distributed generator would be entitled to service fees e.g. availability payments and payments for delivery of flexibility services to the Virtual Lead Party. The distributed generator will also need to consider: the services which it will offer and for what service periods based on the operational parameters of its asset (e.g. via transaction confirmations); its obligations regarding proving tests for its assets; its performance obligations including reporting obligations and how performance failures (e.g. unavailability of assets) will be dealt with (e.g. for planned and unplanned maintenance); communication and metering requirements; changes in law; and termination and termination liabilities where assets are removed from the Virtual Power Plant (e.g. for persistent breaches by the distributed generator).
On Site/ Private Wire PPAs:
This is where electricity is generated on the same site where it is used by the corporate offtaker and the generator has a physical connection both to the corporate offtaker through private wires and also to the grid. The generator may also have a PPA with a licensed supplier in respect of surplus volumes not required by the corporate offtaker and the licensed supplier can act as a back stop buyer if the corporate offtaker is unable to fulfil its PPA obligations. The electricity price achieved by the generator is typically higher than for a wholesale or sleeved PPA and lower for the corporate offtaker than a traditional grid import price because the corporate offtaker avoids non-commodity energy and network charges. Pricing options include (i) fixed price, with some form of indexation; (ii) floating price where supply is priced by reference to an index agreed by the parties; (iii) a cap and floor mechanism; (iv) a discount to market model where the Buyer pays a price based on what it would have paid had it purchased electricity from a licensed supplier (including non-commodity costs) less a discount based on an agreed formula.
When negotiating these types of agreements, the parties must consider and cater for the following issues:
suitability of corporate offtaker’s location for direct connection – upfront capex costs, parties’ responsibilities for costs of connection, access and land rights, delays in construction of private wire and compensation regime; parties’ responsibilities for electrical losses on private wire;
consents and/or licences required – e.g. will the arrangement fall within the Electricity Class Exemption regulations;
creditworthiness of the corporate off-taker;
co-operation of the local DNO so as to ensure sufficient capacity on the local grid to take full offtake if needed;
generation technology and operating costs (particularly, input fuel costs, where relevant);
generator’s projected energy total output volumes andvariability in output volumes plus target energy volumes and metering of volumes sold and bought;
generator’s failure to provide target energy volumes e.g. due to unplanned maintenance and compensation by generator to corporate offtaker in respect of such “availability shortfall”;
buyer’s failure to consume minimum guaranteed offtake and compensation by Buyer to generator for such “consumption shortfall”;
transfer of and payment for green benefits (and how this is affected if generator fails to provide target energy volumes to the corporate offtaker);
termination and termination payments (and caps);
change in control and changes in land ownership; and
change in law - currently charging for public wire networks is based on metered consumption from the grid so electricity which is generated and consumed “behind the meter” is not taken into account even if private network users rely on the electricity distribution network to ensure continuity of supply. However, Ofgem decided in the Targeted Charging Review that, from April 2021, final demand users e.g. industrial consumers, will be charged a fixed charge for use of the electricity networks.
Synthetic or Virtual PPAs:
This is a form of hedge where the corporate buyer and the generator agree to hedge the price at which they buy electricity from, and sell electricity to, a licensed supplier. Both the corporate buyer and the generator each, separately, enter into an agreement with the licensed supplier – the generator enters into a power purchase agreement with the supplier and the corporate buyer enters into a supply contract with the supplier. There is no physical delivery of electricity between the generator and the corporate buyer. The corporate buyer and the generator agree a strike price. If the open market electricity price is higher than the strike price, the generator will pay to the corporate buyer, the excess amount for power generated in that period (a “difference payment”). If the open market electricity price is lower than the strike price, the corporate buyer will pay, to the generator, the shortfall amount for power generated in that period (a “difference payment”). This gives both parties long-term certainty over their power prices. The corporate buyer will also be given green certificates associated with the project in order to demonstrate it is meeting its renewable and/or corporate sustainability commitments. This structure allows for flexibility in the number and location of electricity volumes supplied. The generator and corporate buyer will need to consider, amongst other things, the following issues when negotiating this type of agreement:
financial regulation issues – the parties will need to consider whether the contractual structure will be a derivative financial transaction falling within the Markets in Financial Instruments Derivative (MIFID) and triggering derivative accounting obligations;
appointment of contract administrator – to monitor and record power volumes, calculate difference payments, recommend alternative trading strategies where forecasted generator volumes exceed corporate buyer’s requirements and where corporate buyer’s demand requirements exceed generator’s maximum agreed volume; monitoring, recording and validation of green certificates;
agreed power volumes and volume limitations;
price – i.e. price at which agreed power volumes are sold by generator to licensed supplier and price at which corporate buyer purchases agreed power volumes from licensed supplier;
forecasting obligations;
metering– e.g. daily metering and relevant reporting platforms;
payment schedule for difference payments; and
termination provisions if generator fails to sell required volumes and also if corporate buyer does not purchase minimum agreed volumes and compensation payments in respect of early termination. Parties to also consider compensation payments payable as between them if the power purchase agreement and/or supply contract between the relevant party and the licensed supplier falls away due to such party’s breach.
Sleeved/Physical PPAs:
The corporate buyer enters into a tripartite corporate PPA with the distributed generator and the licensed electricity supplier who will “sleeve” the power from the generator to the corporate buyer in accordance with a PPA (between the licensed electricity supplier and generator under which the supplier takes delivery of the energy from the generator’s site) and a supply contract (between the supplier and the corporate buyer under which the supplier sleeves such power to the corporate buyer at its point of consumption), for a fee. The supplier will also top up electricity delivered to the corporate buyer to meet its electricity demands. The corporate buyer has certainty over how much power it will use and how much it will pay – whilst the generator and the supplier manage the off-take of power from the generating plant. However, this arrangement involves complex contracting arrangements – and the corporate buyer’s reliance on the supplier to provide the sleeving service in addition to electricity supply may reduce its flexibility to change suppliers, unless contract chain breaks are thoroughly worked through.
When negotiating these types of agreements, the following issues will need to be considered:
contractual chain: the terms of the PPA between supplier and generator will need to be “backed to backed” with the terms of the supply contract between the supplier and the corporate buyer;
financial regulation issues – to minimise the risk of the contractual structure being considered a derivative financial transaction, the parties need to ensure the transaction remains physically balanced at all times;
matching electricity volumes to be sold by generator and purchased by corporate buyer and keeping them matched even where one party’s generation or demand is below the expected volume;
management fee/sleeving fee and revisions to such fee if there are market movements or the parties agree to volume changes;
termination provisions and termination payments if there is a break in the contractual chain due to the fault of either of the generator, corporate buyer and/or suppler;
generator’s failure to deliver agreed electricity volumes to the corporate buyer and compensation payable by generator to corporate buyer as a result of such failure;
corporate buyer’s failure to consume agreed electricity volume and compensation payable by corporate buyer to generator as a result of such failure;
credit support to be given by the parties;
change of control of generator;
assignment of contracts by corporate buyer; and
arrangements in place for appointment of replacement supplier in the event of supplier’s default.
Conclusion
The ESO’s power to disconnect distributed generation capacity may affect distributed generators’ sale of power to licensed suppliers who need such power in a different location and therefore need such power to travel over the transmission systems. Furthermore, the Targeted Charging Review decided that, from April 2021, all distributed generators will have to pay for the costs of balancing the grid and will no longer be supported by embedded benefits.
In general, embedded generators bear higher unit costs for each MWh they generate. However, since their electricity is designed to be consumed locally, they have historically saved on transmission costs which larger scale power stations pay (as these use the transmission network to transport their power to its point of consumption by the electricity supplier). However, the removal of embedded benefits and the imposition of a charge on distributed generators for transmission system costs is inconsistent with ‘local’ consumption. Furthermore, these changes will affect wind, solar and battery storage projects more acutely than thermal generation (such as gas peaking plants and CCGTs) as renewable generation will not be able to obtain higher capacity market payments due to their low contribution to security of supply. This all means that the cost of building renewable distributed generation will become more expensive which may impact investor confidence in the renewable generation sector, and, in turn, undermine GB decarbonisation targets.
