The extraordinary developments that have occurred in the energy sector in recent months have led to a tumultuous time for all participants. We have taken a look back through our archives to where we highlighted our concerns a number of years ago that this outcome was, unfortunately, a real possibility. This is an extract from Energy Spectrum, Issue 611, published on 26 March 2018.
The volatility in wholesale energy prices in the last month has led to a focus on what this means for the physical security of supply. But, given wholesale and retail market linkages, in this Energy Perspective, we set out how recent price events, and increased volatility generally, could be impacting new entrant domestic suppliers. Their model of customer acquisition through cheap fixed prices, accompanied by low levels of trading for risk management, makes such suppliers particularly vulnerable to unexpected cost spikes.1,
We argue that the recent events are a reminder to the regulator to resurrect earlier thinking on financial assurance tests for new entrant suppliers to guarantee market integrity and consumer trust.
Supplier failures have been infrequent, but since the end of the 1990s there have been several notable exits, with GB Energy and Future Energy the most recent. Most of these can be linked to sudden rises in wholesale prices (see Figure 1).
Such conditions were evident during the cold weather of the last month. Electricity within-day wholesale prices rapidly climbed to in excess of £300/MWh over the evening peak on March 1. Imbalance prices reached £990/MWh. In the gas market, where the within-day Over the Counter Market (OCM) is used predominantly to balance the market, prices peaked to over 350p/th, the highest price since 1999.
Short-term weather change is not the only factor driving volatility, and more can be expected. In power, we have declining levels of predictable, baseload plant and rising levels of variable low-carbon plant. Cash-out prices will sharpen further in November 2018 under P305. Whilst baseload prices are likely to remain unexciting, intra-day and seasonal volatility will be prevalent. Our wholesale power model clearly indicates a much greater half-hourly standard deviation, as shown in Figure 2.
In gas, the closure of Rough storage will make us more liable to price swings to balance supply and demand, with increasing reliance necessary on imported supplies via pipelines and LNG.
Network costs are also becoming more unpredictable. For example, analysis supporting the CMP287 change proposal shows that in 2017-18 changes in TNUoS forecasting methods to account for embedded generation led to monthly forecast variation of ±20% in some zones for Non-Half Hourly demand tariffs. Naturally, this impacts directly on supplier tariff setting.
Policy costs have in-built uncertainties too. The CfD levy will vary based on actual wholesale prices and generation loads. But there are risks around all of the main items of policy costs, and available evidence suggests these are very challenging to predict for even the smaller suppliers who actively seek to price in these costs.
This greater price volatility is unfolding against a radically changed retail supply landscape. There are now 72 active domestic suppliers. Rates of new entry have blossomed during a period of benign wholesale power prices (see Figure 3).
There is a striking proportion of the supply market less than two years old, and yet to truly establish themselves. Our January 2018 domestic supplier market share survey shows that 52 suppliers account for under 6% market share.
Many of new domestic suppliers have acquired an off-the-shelf pre-accredited licensed company that helps shorten entry timescales and reduce costs. They have looked to grow scale by cutting margins and offering the cheapest fixed tariffs.
Our tariff research reveals that, in the last year, three out of the eight new dual fuel domestic suppliers led with fixed deals only, a further two with fixed deals much lower than their parallel variable tariff, and only two have led with only variable tariffs.
Neither type of tariff is particularly responsive to sudden market changes, but variable tariffs do at least offer a limited time-period of exposure to loss making given the 30 days-notice period to customers before they are changed.
Passing through increases in costs after the fact in tariffs is reactive. Hedging energy purchases is the best route to avoiding margin risk, at least for wholesale energy costs, which on a dual-fuel basis still account for c45% of the bill. However, new entrant suppliers have not traditionally hedged long-term partly through choice, related to costs, and partly through market access.
In their submissions during the CMA investigation of the energy markets, First Utility highlighted a cost differential for trading between the larger suppliers and independents was £30 per customer in normal market conditions. They also noted a lack of forward “shaped” products in the peak demand period “blocks”.
In 2014 Ofgem introduced various measures under Secure and Promote (S&P), its flagship project to address wholesale electricity market liquidity. This obligated the Big Six, Drax and Engie to make available products to support greater liquidity in the wholesale power markets. According to data published by Ofgem in July 2017, S&P has marginally increased volumes of trades, and smaller suppliers have gained better access to longer-dated products. But, granular peak products (for “shape”) are still illiquid.
Options for hedging still broadly fall between either trading through financial institutions or consolidators in exchange for a fee or charges over their business. This may deter new entrants from doing so.
In the gas market, the cost chain includes the shippers, some of which provide wholesale trading services for suppliers for hedging and avoiding imbalance price. However, it is usual for a degree of premium to be added on the pass through of these costs.
Being unhedged through periods of market volatility can have unpalatable consequences.
An illustration of the financial impact is given in Figure 4. This is for an electricity supplier with 10,000 accounts. The horizontal lines are levels of daily revenue collected at different tariff levels – 13.7p/kWh (low), 16p/kWh (medium) or 18.3p/kWh (high), assuming average consumption for the day was 14kWh. These rates are from our tariff database.
The volume weighted average price of power imbalance on 1 March was around £320/MWh for a single rate meter household. The dark blue bars in Figure 4 illustrate the total cost of supply, including non-wholesale costs, at different levels of imbalance. In this example a supplier with 20% electricity imbalance (at £320/MWh) would have been loss making in this period, with costs exceeding revenue. And at the low tariff rate, even 5% imbalance would create losses if tariffs are set at the low-end.
In gas, we estimate that in a worst-case scenario, where a gas supplier had been fully exposed to the gas system buy-price on unhedged volumes, it would have been paying 500p/th.
These costs are not felt instantaneously. There is typically a lag between the incidence of high market prices and cash-calls on suppliers as liabilities are largely payable around a month after delivery. This all points to the prospect of large bills needing to be settled around Easter.
If a supplier is not hedging adequately, one buffer against sudden demands on cash is to take payment from customers in advance, rather than monthly in arrears. This practice is typical, but not exclusive, to recent supplier entrants.
The consumer of a failed supplier has protection against this, but at a wider cost. Where a supplier fails the Supplier of Last Resort process allows for a claim to be made to cover the cost of credit balances, moving this to be recovered via a levy on distributors. This socialises the costs, subject to Ofgem approval on a case-by-case basis.
Without significant supplier failure, the costs are not material (less than £1 a customer for GB Energy). But the principle of all consumers bearing costs for the working capital practices of a failed business sits uncomfortably.
In the GB energy markets, there is no comprehensive assessment of the business or financing strategy of a new entrant supplier. Instead financial assurance is disparately demonstrated by posting credit under a range of schemes and codes. Consistency in approach is already lacking, and complexity is high.
In networks corporate credit strength and good payment history is favoured over cash or letters of credit. In balancing and policy schemes under Electricity Market Reform, cash and letters of credit are the only option. Growth is accounted for by varying the level of credit to volume, but there is no validation of a new supplier’s overall financial capability.
We have previously argued that there is a case for resource adequacy statements to be given by suppliers at entry. This could cover anticipated sources of working capital and approaches to trading. These could be supplemented by on-going reporting process of KPIs linked to working capital performance and profitability once a certain scale of customers is reached.
The idea of “whole-business” resource assessments is not new. The Australian Energy Regulator oversees a scheme where entrants must gain authorisation by demonstrating they can financially support the business until it is profitable, and this includes meeting credit requirements.
In Texas energy retailers must pass a tangible net worth test to enter the market and maintain shareholder funds at a specified level. There are restrictions on dividends if it diminishes the financial strength of the company. Notably, customer deposits above a threshold per customer must be kept in Escrow or in a ring-fenced account, or 100% secured by a Letter of Credit. The levels of the tests are very high, and not necessarily desirable in GB, but they are indicative of the elements of a coherent, workable approach.
After the failure of GB energy Ofgem Chief Executive Dermot Nolan said in February 2017 that “we will review our approach to awarding supply licences, the financial requirements on suppliers, and how we monitor supplier performance later this year”, but nothing has happened since.
We do not wish failure on anyone in the market, quite the opposite. But given the obvious stresses changes in the wholesale market are likely to create for new entry business models in supply, measures which reduce the prospects of such events occurring can only be a good thing for a healthy, sustainable and trusted market.
Robert Buckley commented on this topic in a further three issues of Energy Spectrum in 2018, which can be read here:
Issue 620, published on 4 June 2018. Railroad: Ofgem remains on track for default price cap.
Issue 624, published 2 July 2018. Up for the cup: measuring supply market success.
Issue 634, published 17 September 2018. Iceberg ahead – Ofgem confirms default price cap.