The Price is Wrong: Why Capitalism Won't Save the Planet

by Brett Christophers

the particular industry constituency that the world is relying on to actually, physically, make the switch to renewables – that is, generating companies, those that produce our electricity and sometimes also, in the process, produce greenhouse gas emissions – is seemingly not the industry constituency that would stand most to gain economically from that switch.

Their LCOE indeed is now frequently lower than for a new fossil-fuel-fired power plant. But LCOE measures invariably exclude transport (that is, delivery) costs: they represent solely generation costs, not the all-in cost of bringing power to market.

Indeed, the fact that renewables facilities are disproportionately located in relatively remote locations with relatively cheap land is one important reason why their LCOE – like the cost of the ‘new’ smartphone – is as low as it is.

Products alike in subatomic form can, in reality, be metaphorical apples and oranges in respect of their ability to generate net revenue.

actors involved in operating (and regulating the operation of) transmission grids attempt in various ways to make generators bear the consequences of their locational decisions. In other words, they try to ensure that, say, a wind farm developer that chooses the very cheapest land in the most remote location pays a price, literally, for doing so,

Thus the ‘signal’ referred to by Energy Systems Catapult is considered ‘weak’ in the sense that (some) generators are not currently sufficiently incentivized by transmission charges to develop facilities closer to demand.

The reality of the energy transition that we need to effect is that there exists a vast legacy infrastructure of conventional plants, much of the lifetime costs of which have already been incurred, and hence which are, in the terminology of economists, ‘sunk’ costs

It is entirely possible for renewably generated power to appear cheap on paper relative to conventional sources when average costs over a plant’s lifetime are compared, while nonetheless looking relatively expensive on a power output basis when only costs yet to be expensed are compared.

For our purposes, at this stage of our story, the crucial point is simply that two plants of different types, even if they can produce the exact same amount of electricity over the course of a year, month or indeed day – even, further, if they dispatch and sell the exact same amount of electricity during the period in question – are nonetheless highly unlikely to earn the same income from the sale of that electricity.

A lifetime generating cost that is, for example, 10 per cent lower, is, after all, immaterial if, by virtue of its geographical location and temporal output profile, a wind or solar facility produces electricity possessing, say, a 30 or 40 per cent lower lifetime revenue potential than that produced by a conventional fossil fuel facility.

Essentially, all generators active in capacity markets are conventional, fossil-fuel-fired plants, and thus, in terms of net revenue potential, renewable and conventional generators represent apples and oranges respectively in the further significant sense that they have different sets of revenue opportunities available to them.

One study carried out in 2020 found that no less than around 18 GW of coal capacity in just one US electricity region (the PJM mid-Atlantic market) would be uneconomic were it not for the capacity payments accruing to that capacity.

Inasmuch as its responsibility is to dispatch the mix of generators with the lowest overall cost – an approach known as ‘economic dispatch’ – the system operator accepts the bids of all generators from cheapest to dearest until the point at which cumulative pledged supply meets the expected demand.

All plants required to generate in order to satisfy demand are described as being ‘in merit’; more expensive, non-generating plants are out of merit.

Rather, all electricity traded for a particular settlement period is priced equally, and this uniform price – variously referred to as the wholesale price, spot price or merchant price – represents the bid offered by the highest-bid generator among those dispatched, which is to say the most expensive producer in the merit order.

The standard explanation is that which the Economist recently offered its readers: ‘Just like in any other market for a homogeneous good, the price of power is set by the most expensive supplier.’3 In other words: generators are supplying the same thing, so should be paid the same as one another.

The costs that principally determine the bids placed by renewables operators are the costs of amortizing the upfront capital investment, typically in the form of payments to debt providers – and that is not a marginal cost.

In short, together with the likes of Australia, New Zealand, selected other neoliberal stalwarts such as Chile, and parts of the US and Canada, Europe – including the UK – represents today the heartland of the prototypical electricity spot market as we have described it here.

First, there is the question of which generating source provides the all-important ‘last’ unit of power necessary to balance overall supply and demand within any settlement period.

Hence, if renewables plants can satisfy all demand, then the wholesale price will be established by the bid price of renewables. But if, at the other extreme, electricity demand is high, the wind is not blowing and the sun is not shining, and nuclear and coal also do not suffice – perhaps because nuclear has been phased out on safety grounds and coal on environmental grounds – then the wholesale price will be established by the bid price of gas.

One day, all generators in merit were renewables plants; the next day, gas-fired plants were suddenly in merit, and were burning gas whose price, not least due to the ongoing war in Ukraine and the associated upheaval in gas markets, had soared to nosebleed-inducing levels. How large was the concomitant day-on-day change in the SE3 electricity price? Nearly 1,000 per cent!

As we have seen at various points in this book, the costs of generating power using solar or wind farms, or indeed nuclear plants, can go down as well as up over time. But the degree of variance in such costs over time-scales of weeks or months is as nothing compared to the variance one often finds with conventional generating plants. The reason for the latter cost variance is straightforward: commodity (that is, fuel) prices are themselves often highly volatile.

As it happens, gas-fired plants generated the last unit of in-merit electricity traded in the UK electricity spot market more or less throughout that twelve-month period – more than 80 per cent of the time, despite the fact that such plants accounted for less than 40 per cent of the country’s electricity supply over the same period.

But UK electricity prices were nevertheless highly volatile, precisely because natural gas prices were so volatile.

electricity price volatility is the result sometimes primarily of fuel price volatility, sometimes primarily of changes in the identity of the provider of the last in-merit unit of power, and sometimes of both.

In the absence of overt mechanisms of price stabilization, spot market price volatility has – in places such as the UK – a profoundly chilling effect on renewables investment.

There is, in short, a deep and impactful aversion to taking on so-called ‘merchant risk’ – that is, the risk associated with selling renewably generated electricity exclusively or predominantly at volatile merchant (wholesale) prices.

Instead, when renewables projects wither on the vine because of aversion to price volatility risk, the decisive aversion is usually that of another actor – namely the banker.

Insofar as it militates against the knowability of future income streams and of debt-servicing capacity, spot-market price volatility is pure anathema to the banker’s calculus.

‘investors rightly require higher expected returns, often in the mid to high teens, to compensate for the risk of investing in a highly cyclical industry’.

The obstacle, rather, is the effect of price volatility on the perceived investibility of projects under development.

Far from anticipating price volatility to decline any time soon, they widely expect it to persist, and perhaps even intensify.

very many fossil-fuel-based electricity plants around the world in territories that today feature liberalized wholesale markets were financed without the price volatility characteristic of such markets having to be considered. The markets did not yet exist.

Essentially, the use of merit order dispatch and the status of gas as the predominant source of the last unit of dispatched power combine in such a way as to afford a certain symmetry of revenue and cost dynamics for gas-fired generating plants. In the terminology of finance, there is an inherent hedge.

In countries with advanced electricity wholesale markets, gas-fired plants remain in certain respects easier to finance than renewables facilities, even – and the subclause is crucial – if gas-generated electricity is more expensive than renewable power.

One of the most common is a futures contract, which is an agreement to buy or sell an asset at a predetermined future date and price. If the developer’s concern is that prices in the electricity spot market might fall, it can hedge by taking the sell (‘short’) side on electricity futures contracts.

Research

Electricity swaps are especially common in Texas. Because most electricity generated in Texas is sold through its spot market, the demand for hedging mechanisms to ensure project bankability is commensurately large there.

Typically, these schemes simply provide a revenue premium for electricity that is renewably generated. For example, if ‘normal’ electricity earns €40 per MWh in a certain spot market, a wind farm might earn an additional €2 for the fact that its product is green. But that does nothing to help with volatility. If the spot price drops from €40 to €20, the wind farm’s per-MWh revenue drops from €42 to €22.

By contrast, instruments of government support based on price controls can explicitly provide stability, even if not all do. Feed-in tariffs (FiTs) and comparable instruments are the exemplars here.

The generator enters a long-term contract, essentially with the government, stipulating an agreed fixed ‘strike price’ for the contract’s duration. It then sells its output on the spot market during the years when the contract applies. But, if the spot market price (the ‘reference price’) falls below the strike price, the generator is compensated for the difference, while, if the reference price is above the strike price, the generator must pay back into the scheme.

‘CfDs incentivise investment by giving greater certainty and stability of revenues to electricity generators by reducing their exposure to volatile wholesale prices.’26 In other words, the use of CfDs (and FiTs) is as much about intervening in, and shaping, markets for finance as it is about shaping markets for electricity.

Feed-in tariffs and the like ‘give you revenue stabilization’, one banker stated, ‘and that’s the key’.28 They are thus the gold standard for investors in renewables.

Equally, one of the main reasons why financial hedging instruments like swaps and futures contracts are so significant in a place such as Texas is precisely because the US’s own long-preferred forms of government support for renewables – the ITC and the Production Tax Credit (PTC) – do not confer price stability. This is not to say that such government support has been misguided, still less immaterial. Far from it: it has been indispensable. But, in a place like Texas, where electricity is traded predominantly in the spot market and price volatility is therefore endemic, tax credits historically have been necessary but typically not sufficient to generate project bankability.

In short, for all the allure of government funding in the shape of reduced costs (the ITC) or extra revenue (the PTC), tax credits do not mitigate me...

Now that renewables are not relatively dear, government support – at least in territories or regions with the aforementioned market and regulatory features – is designed primarily to stabilize.

‘If you think I’m building a £2.5bn wind farm at merchant risk on wholesale power prices’, Anderson said, ‘then you’re bonkers.’

The world, in short, is moving towards, not away from, electricity spot markets, price volatility and correspondingly poor visibility around the expected profitability of renewables generation.

Tillerson’s answer was withering. ‘As to investment in renewables, quite frankly, Father Crosby,’ the CEO said to loud applause, ‘we choose not to lose money on purpose.’3

The facility could be hugely profitable, but, equally, it could make disastrous losses: price volatility is that extreme. This matters because, in a capitalist economy, expected profitability is the measure according to which investment decisions are made.

what, with the benefit of hindsight, are we able meaningfully to say about the circumstances in which renewables generators do in fact prove to be consistently profitable? The most notable and important fact is that the vast majority of such cases share a signal, common feature, whether the output is being sold mainly in wholesale spot markets or indeed under long-term contracts, as is principally the case in, say, India. That common feature is effective government support for renewables, of the kinds examined in earlier chapters.