The threat to European consumers from soaring gas and electricity prices has dominated recent headlines and impacted bond prices, but informed discussion of the implications for Utilities companies has been lacking.
The supply squeeze caused by the conflict in Ukraine, exacerbated by existing market design, has created three major potential issues for the Utilities sector, essentially involving cost, supply and liquidity:
- Cost: The cost-of-living crisis could lead to an increase in bad debt expenses, as well as the expense of windfall taxes imposed by governments to counter surging prices.
- Supply: Blackouts caused by interrupted or insufficient supply could lead to loss of volumes and revenues.
- Liquidity: The regulatory requirement for utility companies to post collateral for hedging purposes is creating a working capital squeeze for electricity generators.
In the long term, market design will need to evolve — an issue we will cover in a future note. However, in the short term, these issues create both risks and opportunities for investors.
Why have utility prices climbed so high?
The utilities value chain consists of upstream (generation), midstream (networks) and downstream (suppliers) subsectors. Within Europe, large utilities are usually integrated businesses that cover the whole chain.
Currently, the European market works on a marginal pricing system, with electricity prices the outcome of hourly auctions at 24 hours’ notice. The system operator forecasts demand, and generating companies then offer capacity and a price. The operator starts by accepting the cheapest offers, continuing up the price scale until enough capacity has been secured to cover expected demand. The last ‘marginal’ offer accepted sets the price for all the electricity to be supplied.
As a fixed cost technology, renewables can offer electricity at a predictable price. In contrast, thermal (coal and gas-fired) power stations are vulnerable to variable costs, most notably in the form of input prices for the gas or coal itself. Coal-powered stations tend to be uneconomical and therefore often go unused. As a result, gas plants set the prices around 75% of the time, despite only producing around 20% of electricity needed.
Figure 1: Electricity auction prices largely correlate with the share of thermal production in the mix
Unfortunately, in a supply squeeze this market design can create significant price volatility. Most recently, a lack of hydro-supply due to drought has coincided with French nuclear capacity being offline for checks. This has further stressed a market already reeling from significantly reduced gas supply from Russia. As a result, despite government intervention, as at August 2022, Spanish spot prices were around six times the average for 2017-2020. Meanwhile, in France the lack of a cap meant they were up to 12 times higher (see Figure 2 below).
Figure 2: Comparison of spot power prices in Europe, 2017-2022
While changes to the way the market functions are clearly needed, any redesign will take time to develop and approve. In the meantime, efforts to address the crisis are taking three key forms: refocusing supply, providing fiscal stimulus to consumers, and offering a liquidity lifeline to utilities firms.
Prior to the current crisis, the EU relied on Russia for around 40% of its gas supply and more than 50% of its coal. Eastern and Northern countries are most dependent, with France, the UK, Spain, Belgium, the Netherlands and Portugal largely immune. The affected countries have already reduced their reliance on Russian gas. However, a lot more needs to be done.
Potential measures that can be taken to reduce reliance on Russian gas include:
- Increased use of liquefied natural gas (LNG): Seven floating terminals to process LNG should be online in time for winter. Another 19 are planned, along with seven onshore terminals. Supply deals for LNG have been struck with the US, Qatar, Azerbaijan, Egypt and Israel.
- Reopening of coal and nuclear power stations: Germany has announced that two nuclear plants previously due to close will be kept open temporarily. Coal-powered stations could also be used more, although supply shortages may become an issue.
- Fuel switching: The current price of oil makes switching from gas to oil-fired generation economically viable. Some plants could also be adapted to use alternative fuels such as biomethane.
- Reducing consumption: EU countries have agreed to a 15% reduction in gas this winter, relative to the 2017-21 baseline. As recession sets in, the resultant demand destruction will help, while prices will weigh heavily on demand where they are unsubsidised.
In the UK, tariff freezes mean energy suppliers will be required to charge households at a reduced rate, with the government guaranteeing financing to cover the shortfall. This arrangement is credit positive for the sector, as energy suppliers are swapping riskier customer debt for government-backed debt.
In Europe, the EU is exploring a three-pronged approach:
- Coordinated reduction in demand: Peak electricity consumption would be reduced by encouraging use to be shifted to nights and weekends. As with the scheme to reduce gas demand, Member States would request bids from consumer categories (e.g., industrial; aggregated retail consumers) for financial compensation to cut consumption.
- Price cap for inframarginal technologies: Clawbacks would be imposed on cheaper electricity producers such as renewables, nuclear and coal, set high enough not to discourage future investment.
- Consumer support measures: The cap on excess inframarginal profits would provide additional revenues EU Member States could use to lower tariffs for selected consumers, potentially including SMEs.
These fiscal measures will help tackle the cost-of-living crisis and mitigate the potential impact on suppliers in the form of bad debt expenses.
One somewhat counterintuitive issue is the liquidity problem affecting electricity generating companies. This is a working capital squeeze rather than a solvency issue.
Generators seek financial stability by taking short positions in futures markets before selling the physical electricity. If power prices fall, gains from the short position mitigate any losses on a contract; if prices rise, the additional profit on the physical delivery should cover the cost of the short.
Current market rules require the posting of additional collateral to the exchange if the price of the underlying asset rises. Soaring electricity prices have meant these collateral requirements have ballooned, sometimes overnight. Although positions will become profitable once the physical energy is sold, with many not maturing for months or even years, companies risk exhausting their existing credit lines.
While the situation has been described as a potential ‘Lehman moment’, no sane government will risk its utilities going under. One solution the UK Government is already pursuing is to provide state-backed credit to help energy companies access additional liquidity. Another, which the EU is considering, is to modify the rules around margining.
Current regulations fail to distinguish between hedging by companies who own power generation assets and pure financial speculation. Reducing or removing the collateral requirement for electricity producers should ease the liquidity squeeze on utilities with minimal risk to their counterparties. In conclusion, this is a risk that is likely to be relatively well managed through government support.
An awareness of how these multiple issues will affect specific subsectors and companies makes it possible to adjust exposure to maximise long-term opportunity while minimising risk. Our positioning considers the following:
- Midstream companies providing transmission and distribution networks operate in a highly regulated space; they are therefore immune from the crisis and continue to be a strong investment.
- Electric Utilities are better positioned than gas Utilities, and this essentially gas-led crisis does not affect our medium-to-long term structural underweight to gas Utilities; decarbonising our society means first and foremost electrifying it.
- Utilities with no Russian gas exposure are less likely to be affected by enforced blackouts due to supply interruption, and the resultant loss of revenue.
- For utilities that suffer disruption to electricity production, higher prices should compensate for any loss in revenue.
- Corporate hybrids from Utilities who may need liquidity support are best avoided – companies accessing government backstops may find this treated as state aid under EU rules, which would trigger mandatory coupon deferral (as happened to German airline Lufthansa during the pandemic).