Energy prices have been in the news again, with price increases from many suppliers and the publication of the intended level of the retail price cap. There are a number of drivers of energy prices, with network and policy costs making an increasing impact on final bills, however the single largest contributor continues to be the wholesale cost of gas and electricity.
Wholesale gas and electricity prices have been rising rapidly over the past year
After an extended period of relatively benign market conditions, this summer has seen significant price rises for both gas and electricity. Most suppliers outside the Big 6 purchase the gas and electricity they sell to end customers is the wholesale markets through a variety of mechanisms. The markets can be traded “spot” – typically the purchase of gas and electricity for delivery on the following day, or “forward” with products over different time periods in the future. Gas is more liquid in the wholesale markets than electricity, and can be traded further into the future. Within-day trading is also possible.
Ideally, suppliers would buy the majority of their gas and electricity in the forward markets, locking in prices for 1-2 years in the future. This protects them against adverse market movements. A portion of the supply needs would be procured on a short-term basis to reflect the volume uncertainties faced by suppliers, with the intention of minimising exposure to volatile imbalance prices.
Early 2016 saw the lowest wholesale electricity prices for several years, but since then prices have risen by 82%, driven by increases in gas prices (themselves driven by international gas markets and the rising oil price). Winter 18 gas and power contracts are up by 52% and 50% respectively over the last year. Prompt prices have also seen significant increases, with electricity rising almost 50% since the beginning of the year:
Gas-fired power stations are the marginal generators in the GB electricity system, so gas prices play a major role in setting electricity prices. The decline in domestic production alongside the closure of Rough – the UK’s only large long-term gas storage facility – have increased the country’s reliance on pipeline imports from Europe and LNG imports from the Middle East, and now the US. In this sense, Brexit is also making itself felt since as the pound weakens against the euro, the costs of these imports has risen.
Weather is also playing a role, with the impacts of the “Beast from the East” in the spring, followed by an unusually long and hot summer. The increase in solar generation has been met by an increase in load through air conditioning (particularly in Asia which has driven global prices up), meaning that European gas stocks have not had the opportunity to recover ahead of the coming winter.
The high temperature/high pressure weather systems this summer have affected European power generation with nuclear stations reducing output due to problems with cooling, and low wind depressing renewables output.
Finally, there has been a significant increase in the price of EU carbon allowances this summer, from just under €6 /tonne a year ago to a high of €21.8 /tonne on 27 August. The requirement for generators to procure allowances for the carbon they emit means that these costs influence both the merit order and the wholesale price of electricity (see box below).
While short-term (intra-year) weather patterns have a fairly short-lived impact, the other drivers of electricity prices are more fundamental, and unlikely to reverse any time soon – gas and power contracts for Winter 19 have also risen over the past year, but by a smaller degree – 34% for gas and 38% for electricity.
Wholesale price rises putting real pressure on suppliers
When wholesale prices rise, prices to consumers will rise irrespective of the buying strategies of the suppliers. Larger suppliers with comprehensive forward hedging programmes will be able to absorb some price increases since a significant portion of their supply will benefit from fixed prices, limiting their spot exposure. However, future supplies also need to be secured, so while companies may adapt their forward purchasing programmes in response to market conditions, they will generally want to avoid speculating on falling prices since prices could rise further, meaning they may end up locking in higher prices for future supplies if forward prices rise in line with prompt prices.
For smaller suppliers the picture is significantly more complicated due to their limited access to forward markets. Despite Ofgem’s efforts with the Supplier Market Access regulation, market access remains difficult for small suppliers due to their problems with securing trading credit lines. Buying forward creates a credit exposure for the seller with respect to the buyer, since the buyer is bound to purchase an agreed volume at an agreed price at an agreed time.
If the seller is a generator, a default by the buyer will mean it would have to sell its production in the spot markets which may mean achieving a lower price (and exposing the generator to a potential negative spread if it had purchased its fuel forward at higher prices). If, on the other hand, the seller is not a generator, it will have hedged itself in the forward markets and will be itself committed to purchasing on similar terms.
As a result, sellers face significant credit risks with respect to the buyers and will therefore seek to mitigate those risks, by either taking collateral, requiring margin payments to be made, or restricting the volumes and tenors it will trade with any individual buyer.
This is problematic for small suppliers who typically lack the resources to provide either collateral or margin payments, and therefore find themselves locked out of the forward markets, leaving them fully exposed to spot prices.
Smaller suppliers therefore must immediately pass market price increases on to their customers to avoid incurring losses. This is also problematic since many smaller suppliers seek to compete on price, in particular by offering fixed price contracts which leave them exposed to rising market prices.
In a rising market, larger suppliers with forward hedging programmes will have more flexibility around the timing and size of any price increases and will have been able to fully hedge their fixed price tariffs, while smaller suppliers will face significant pressure to pass on all wholesale increases in full as soon as possible, potentially damaging their competitiveness, and potentially absorbing losses on fixed price contracts.
Smaller suppliers that lack the ability to buy forward are suffering not just from the inability to secure their procurement costs into the future, they are also missing out on the ability to take advantage of the current backwardation in gas and power prices. Forward markets are in backwardation when the prices for forward contracts decrease the further in the future they are delivered.
This tends to reflect current short-term supply/demand issues rather than any fundamental expectation of lower future prices, however smaller suppliers that cannot buy forward are fully exposed to those short-term pressures.
These dynamics are putting significant stress on the finances of smaller suppliers – five have already closed so far this year, and more are likely to follow if current market conditions persist. And suppliers across the board are raising their prices – in the case of challenger firm Bulb Energy, for the third time this year, this time by just over 11%.
Impact of the price cap
Ofgem expects its methodology for assessing the wholesale costs contributing to the retail price cap to influence the hedging behaviour of suppliers. It sees wholesale costs as the most challenging aspect of setting the price cap, and has indicated it will use a “6-2-12 semi-annual approach” to calculate the weighted average wholesale cost of gas and electricity over a 12-month period, which involves a six-month observation period of daily index values in the lead up to the cap period, a two-month lag before the cap level is announced and a 12-month forward view of contracts delivering during 12 months following the start of the price cap.
Ofgem has considered various different approaches for benchmarking for wholesale costs, each of which has its challenges. Reported wholesale costs vary significantly between suppliers depending on their purchasing strategy, particularly how far out they have hedged, and the impact of shaping, imbalances and transaction costs must also be taken into account.
Stakeholders raised concerns to Ofgem that the 6-2-12 semi-annual model would prevent them from being able to fully hedge against price changes, because the level of the default tariff cap in any single six-month price cap period is based on prices for a 12-month delivery period, so to follow it, suppliers would have to buy products outside of the cap period, the price of which would not be used to assess the allowance for the following cap period. Alternatively, they may choose not to closely follow the hedge.
“Suppliers have strong incentives to follow a buying strategy that matches the valuation given by the way we assess wholesale costs. This is to reduce the risk that they incur costs that exceed the allowance included in the level of the default tariff cap,”
Ofgem believes this is the lesser of two evils since otherwise suppliers may reduce their hedging activities further down the curve (although this could in fact level the playing field in that smaller suppliers already do not hedge very far forward). Ofgem was also concerned a shorter window lead to seasonal variations in wholesale prices feeding through into high winter prices and low summer prices for consumers, something suppliers currently avoid in their tariff structures.
Ofgem has considered how non-energy costs including broker and exchange fees, the cost of operating a trading desk, and the cost of credit and collateral should be treated. The level and materiality of these costs is likely to differ significantly across the supplier group with smaller suppliers paying high market access and collateral costs while larger suppliers are likely to have more substantial and therefore expensive trading operations. In setting allowances for these costs, Ofgem must find a mechanism that allows for different operating models across the sector.
“The nightmare scenario for Independent suppliers without access to infinite cash flow is that costs increase significantly above the cap due to unexpected world events affecting wholesale prices such that their capped SVT tariff becomes loss making and its fixed price customers opt for it at the end of their current fixed term as it will be the suppliers’ cheapest tariff,”
– Bristol Energy
In responding to the various consultations of the issue, suppliers have raised their own concerns, including that the approach could force smaller suppliers to adopt long-term hedging which requires large amounts of working capital.
“We think the method outlined for updating the wholesale price could have unintended consequences in the wholesale market. It will likely cause short term prices to rise as all suppliers’ purchasing aligns with the biannual cycle of price cap increases. The impact will be felt more by non-vertically integrated suppliers, who have less [sic] balancing tools available to them and may have less capital available to hedge over longer periods,”
– Co-op Energy
This is an increasingly difficult market for smaller suppliers to navigate. Unlike the Big-6 and new entrants such as First Utility that is backed by oil-major Shell, most challenger suppliers are neither vertically integrated having access to their own supply, nor have the financial and operational resources to adopt the most efficient hedging strategies. This leaves them very exposed to an increasingly volatile wholesale price environment, and with the cap looming, threatens the stability and sustainability of their business models.