Be informed

I wrote last month on Andreas Malm and Wim Carton’s book, Overshoot. Like all arguments – and their book is full of them – there are weaknesses. Or in my case, a failure fully to understand. In pursuit of that understanding, I have turned to an extraordinary book by Brett Christophers, the Price is Wrong – Why capitalism won’t save the planet (right).

Christophers waits until chapter 6 – appropriately entitled, The Wild West, to broach the point of why. It is not because the previous chapters were superfluous – far from it. Rather it is because electricity is complex, and despite out belief that all electricity is the same, Christophers has to make the case that not all electricity is the same.

First, we have to look at the structure of the liberalised (i.e. non-vertically integrated markets), of which the UK is a prime example after privatisation in the 1980s. Let me break down some of the stakeholders in the system:

• Generators – owners of power plants (some located outside of the country)
  • renewables
    • wind
    • solar
    • hydro
  • non-renewables
    • gas
    • coal
    • biomass
    • nuclear
• Last-mile suppliers.
  • Buyers of wholesale electricity for supply to end users (domestic and businesses)
• Electricity System Operators (ESOs)

Markets

Increasingly the industry’s liberalisation has led to regulated markets being constructed by policy makers. In the UK there two distinct routes to market by generators.

• spot markets (electricity for immediate use)
• corporate – Power Purchase Agreements (PPAs) – generator contracts directly with corporate entity which is often a large user of electricity. There can also be PPAs between generators and utilities (retailers).

Spot markets trade in blocks of time, 30 minutes in the UK, for example. There is a base load, usually supplied by renewables and then a top-up, usually coming from the most flexible of supplies; namely, gas. In the UK the last coal-fired power station closed in September 2024.

Spot markets and volatility – why renewables are unattractive to investors and fossil-fuelled plant is attractive

The prices of electricity on spot markets are volatile. They are volatile over each day – demand can vary widely from the peak of the early evening to the overnight lull. But volitivity over a month…that seems to be more scary to investors. For example (p 170) in February 2022, spot market prices in Germany ranged from under €50 per MWh (day 19, Saturday) to just under €250 per MWh (day 25, Saturday). Demand is difficult to predict; indeed, we might ask, are there any other (commodity) markets with such pronounced volatility?

If you are an investor – a bank, for example – such volatility instils a sense of unease. It does not make investment impossible, but it makes it more expensive. Christophers’ research suggests that interest rates for renewable energy projects can be as much as 3x that of non-renewables.

We should then ask, why would a gas-fired power station – that sells into the same volatile market – not also be high risk? There are two things to be aware of here. First, banks have been investing successfully in fossil fuel projects for many years. Successfully. It is a known and tangible entity that has largely been low risk. Bankers, however, when making investment/loan decisions ask one simple question, will the client be able to pay back the loan on any terms agreed? The banker wants to know how much income the project will be generating to service the debt. The project owners will, of course, not be able to answer that question because of the volatility. It seems to be insufficiently adequate for the loanee to say that they are 100 per cent certain that all electricity they generate will be bought by suppliers because what they generate will always be cheaper than electricity generated by gas. The spot markets always include the lowest-priced electricity in a merit hierarchy.

There seems to be other issues here for investors. The returns on renewables is lower than that for fossil-fuelled plant. Typically, noted by Christophers (pp 211-221), fossil-based investments can generate returns of up to 20 per cent. Renewables come in at between 4 and 9 per cent. If we consider oil company shareholders, they are offered by the executive investments that will bring in double-digit returns, or equivalents that will deliver at best half of that. What will they choose? And what if the executive takes the decision to go with the renewables, knowing that their returns will be lower? Most will be out on the ears at the next shareholders’ meeting. These are so-called opportunity costs. Investing in renewables means that the investment will not be made elsewhere; i.e. something that brings in a higher return. But, argues Christophers, the shareholder concerns are minimal in comparison to that of the banks. Banks are looking for double-digit returns. It is also the case that many investments in renewables are made by companies that are not fossil-fuel based. They specialise in renewables. They will only deliver across their portfolio single digit returns to a market that is volatile, that exhibits the so-called merchant risk. Added to that, renewable plant is part of a “transition” – an energy transition. That transition, argues Christophers, has two elements. The first adds to the uncertainty. Transitions by definition are uncertain. The second is transition has no history. Generators are asked to project into the future with no historical data on which to make the calculations.

We might then ask, what about owners of plant fired by fossil fuels, how do they make the case to investors if they sell into the same volatile electricity market (because new gas-fired power stations are still being built)? Well, it seems quite simple, a traditional fossil-fuelled power plant is not part of a transition. It is proven technology and can demonstrate historical returns on investment. It is eminently bankable.

And here is another scenario. If the spot price of electricity (say in the UK) falls, so does the price of gas. The spot price is determined by the gas price (or the highest bid price in the bidding round, usually 30 or 60 minutes in each 24 hour period). In that scenario, the price of gas falls and the bid posted for electricity generated by a gas-fired power station is at a lower price because the primary cost of the power station is its fuel. If the gas price falls, so does the cost base of the plant. There is a hedge at work in the eyes of the bankers (p180).

The same is not true of wind-based renewables plant. The fuel – wind – is a gift of nature. It is free. The cost base of the plant, in the event of the spot price decreasing, does not decrease. That seems to indicate to bankers that there is a point where there is no return, and hence the ability of the plant owner to service the debt. In other words, finance cannot be secured because the fuel is renewable, meaning that even if the turbine is turned by the wind it can still be used by another wind turbine. But non-renewables once used are used. It is counter-intuitive that this is a positive and hence a challenge to bankers. In essence, then, there is a significant merchant risk; namely, “the risk associated with selling renewably generated electricity exclusively or predominantly at volatile merchant (wholesale) prices.” p174

Work arounds – how renewable plant owners can hedge the risk

Christophers offers three ways around this problem.

• Option 1: the futures contract. This is a situation whereby the electricity will be bought and sold at a predetermined price. The fear/danger is that the spot price falls such that revenue is flat and threatens not to cover liabilities. This is a balancing act where an option to sell (short) on the electricity futures contracts means that if the spot price does fall, the negative outcomes in terms of income “earned” in the spot market are compensated for by a gain in the futures market. Essentially, the trading value of the contract enables the sale to be transacted at a fixed future price which typically rises as the spot price declines. This is a common mechanism for hedging in liberalised electricity markets.

• Option 2 – swaps. These are more common in North America and Texas in particular. Swaps act as substitutes for futures contracts. The principle is that a party averse to risk relating to falling electricity prices can offset the risk by entering into a swap that pays out even if electricity prices fall.

Hedging, though, is complex. Only the largest producers have the so-called competence to hedge at scale. There are at the very least significant cash flow challenges. For example, if the spot market does decline, one party has to put up considerable cash to cover the decline. There is even a bigger challenge to contemplate. Christophers asks fairly, what happens if the renewable electricity supplier cannot supply the amount of power it is contracted to supply to the futures or swap markets? The above relate to Christophers’ arguments on pages 178-183.

• Option 3 – PPAs – these reassure banks that there will be a return sufficient for loan repayments.

• Option 4 – government subsidy/support. Such support has its own hazards.

1. investment grants do not help in pricing
2. Investment Tax Credits can help reduce the level of break-even spot price
3. Price controls/Feed-in Tariffs (FiTs) – compensating generators when the spot market “reference” price drops below the contract “strike” price; though when the strike price climbs above the reference price, generators pay back into the pool. The net price is always the strike price.

Price controls stabilise markets and satisfy investors. But then introduces yet another source of uncertainty. Will governments – especially when they are fiscally stressed – honour or extend FiTs rates? Unless they do, renewable generators are back to spot price volatility. Christophers offers examples of state withdrawal in China and India (pp.

Notwithstanding problems with subsidies (option 4), markets can bankrupt renewables generators. In Texas in February 2021, a bolt of cold air caused a number of generators to cease as their equipment, not used to such extreme conditions, seized up. This was not just renewables generators. Fossil-fuel plant also seized up. As a result of the limited supply, electricity spot prises went up considerably. Renewables generators were supplying into a market with spot prices below $100 per MWh (as low as $50). During the crisis, prices were $9000 per MWh. Now if renewables generators were selling into that market, then there was money to be made (assuming the turbines were working, of which many were). But if the generators had PPAs at fixed prices, if they were unable to supply they had to go into the spot market to meet the terms of their PPA. That was enough to bankrupt generators (p310).