Why should renewable producers worry about energy market prices?



Author: ABB European Advisors

Being a renewable producer – be it wind, solar or other cutting edge technology – is worrying enough. But now, not only do you need to worry about whether the government is going to change its mind yet again on future subsidy arrangements for your next project under development; you also need to worry about the income streams of your existing sites, as both current and past subsidy arrangements are being changed. Subsidy arrangements, market designs, curtailment, grandfathering…nothing seems to be guaranteed any more as cash-strapped governments and households eye rising energy bills and subsidy costs.

What’s the worst that can happen? That wind farms and PV lose their “dispatch priority” status, and instead of their output being taken regardless of demand or market price, they have to compete and “bid” in the market on the same basis as all other forms of generation. That their feed-in tariff contract gets changed or removed; for example is changed from a fixed price to a some form of premium linked market price, as in Spain (see below). That their “grandfathered” status, where current tariff levels remain unchanged regardless of how the market turns out, is removed, and they have to take the latest (reduced) tariff offering.

What’s the outcome of this? Precise outcomes will be market and technology specific, but an increasingly likely result is that renewable generation will be exposed to market price and volume risk. In other words, for the first time, renewable generators may not be able to guarantee that all their output will be paid for, and also may not know at what price.

The threat is real – in December 2013 two investment funds linked to Deutsche Bank and BNP announced they were suing the Spanish government as the new renewables reform would significantly reduce the income from their Spanish solar investments. They claim that they made the investment in 2012 under the impression that “both plants benefit from a transparent, stable and attractive regulatory framework with the sale of its guaranteed production during their operational lives.” The new power reform bill effectively scraps existing renewable feed-in tariffs (along with those for wind, CHP and other renewable investments), and replaces them with a variable payment based on investment and operating costs. “Grandfathering” appears to have been abandoned, and the 25 year contractual terms ignored as the heavily indebted Spanish government grapples with an annual renewables tariff deficit of at least €3.6bn.

Aside from the straight reneging of contractual agreements, other examples of creeping market risk include the swapping of a fixed FiT for a premium to market prices or some other mechanism (such as the CfD being introduced in Britain) which gives renewable generation an incentive to deliver at times of high price or curtail (turn off) at times of low (or negative) price rather than being entirely indifferent. It also gives them a stake in boosting wholesale market prices, as this will increase their revenue.

Specific remuneration schemes for curtailment are starting to be introduced, which are very likely to include an element of market-based pricing. The German “market premium” scheme allows renewable generators to give up their FITs and instead sell their output directly into the wholesale power market. Generators pay a management fee, and in return are paid a market premium based on the average monthly price on the EpexSpot power exchange. If they manage to sell their output at a higher price than the EpexSpot price, they make a profit. Participation on this scheme – expected to start becoming compulsory for renewable generation from end 2014 – requires renewable generators to be able to anticipate market prices, and, depending on the management fee, could prove to be a significant income risk to generators. The current voluntary scheme had over 38GW registered in April 2014 , and its impact is already being felt. For example, on 13 June 2013, Norwegian state-owned Statkraft cut wind power supply to the day-ahead market in the spot auction for delivery on 16 June, when hourly prices settled as low as -€100/MWh. Hourly prices could have fallen to as low as -€300/MWh had Statkraft not cut wind power output, the utility said at the time.

These contractual and regulatory changes mean that renewable generation would be, for the first time, exposed to variations in market prices. Is this likely? It largely comes down to your view of the integrity of politicians and your expectations on how quickly market designs can change. In reality, no one knows, but we would strongly suggest that all renewable generators start to understand the realities of the energy market in order to be prepared for all eventualities. And in particular, the realities of the energy market for generation that is poorly correlated with demand, and with a limited ability to “price seek”.

This paper looks at the average income profile for PV and wind farms, compared to average income for flexible fossil generation, and discusses the relative income disadvantage renewable generation has.

Large volumes of renewable generation tends to depress prices when generating. This is because they have much lower marginal costs of generation compared to competing (generally fossil) generation. For the wind and solar PV generators who are generating during these periods it means that they will receive lower prices over the year than a typical (fossil or nuclear or controllable hydro) generator.

As the below graph shows for the German market, a solar PV and onshore wind (on) producer can expect to receive up to 10% less than a baseload fossil producer would average (equivalent to around €5/MWh), simply because it tends to generate more in lower priced periods. Based on ABB’s hourly forecast generation profiles, off-shore wind fares slightly better, a result of an improved correlation with higher priced periods.

Germany, % difference in income (€/MWh) to baseload prices, annual
RRR_1
Source: ABB, inc.

It is worth noting that particularly windy/still/cloudy/sunny periods could change this picture substantially. A more detail look at monthly trends gives some insight into why solar appears to be consistently underperforming both wind and fossil plant on an annual basis. Solar earns more than either fossil or wind plant during the Winter period, in €/MWh terms: it more consistently generates during the relatively high priced days. It misses the traditional 5pm peak pricing period, when it is generally dark in Europe, but as it is not generating during the relatively low priced overnight period, it generally outperforms baseload generation on a €/MWh basis. However, solar tends to generate less volume in Winter, producing more output during the Summer period when prices are generally lower, and there is a surplus of must run generation lowering prices. So overall across the year, solar underperforms against baseload generation, as its income is biased towards the lower priced summer periods.

Wind production is more dispersed throughout the year, though unlike solar generation tends to produce more in winter than summer. However, wind generation is too intermittent to be able to “pick” the highest priced periods – and turn off during unprofitable (zero or even negative) periods like flexible fossil units can.

Germany, % difference in income (€/MWh) to baseload prices, monthly
RRR_2
Source: ABB, inc.

A look at the British market shows a different picture – solar PV actually enjoys a surplus to average baseload price, while wind – particularly off-shore wind – has only a slight deficit for the next decade. At first glance, the picture looks relatively encouraging for renewable generation, and indeed it is for the next decade. Once viewed in conjunction with the above graph showing the market share of generation, the picture becomes clear – Britain is a relatively late starter in renewables. For the next decade, renewables enjoys a relatively small market share, and so do not depress prices in the same way as is currently being seen in Germany. Prices are less volatile, and there is rarely a surplus of “must run” capacity driving prices down at times of low residual demand. As a result, intermittent plant fit well into the merit order, and have little to worry about from exposure to market prices in the short term.

RRR_3
Source: ABB, inc.

However, that picture starts to change as (if) the renewable boom takes off as predicted in the UK. Renewable generation gets “trapped” in the electricity system, which has relatively small interconnectors with its neighbours, and wholesale prices will drop to zero to reflect this surplus. While flexible generation can turn off, renewable generation’s marginal income would fall – particularly for the most dominant renewable generation source, wind.

How to mitigate this? Other than protection via contract or portfolio optimisation (to balance the risks through a diversified portfolio), a highly interconnected system would limit price volatility and collapse. Renewable generation can instead displace higher priced power elsewhere in the system, for example more expensive fossil running in Eastern Europe, or allow the Swiss or the Scandinavians to turn off their hydro and store water behind the dam for later use when it’s not windy. However, this is limited by the size of the interconnections and hydro reservoirs (which are still relatively small in practice), and also by the ability of traders and market operators to quickly allocate the power. Market coupling and the new European target model (which includes the aim to promote more cross European power flows) is assisting in this, but there is still a way to go here and unlikely to be a short (or even medium) term solution.

A practical measure in the meantime would be for renewable generators to improve their understanding of their future potential income streams outside their current protected FIT arrangement, or, in short, to worry about energy prices. This would involve understanding wholesale market price projections and trends, and what drives them. This understanding needs to be simultaneously market-wide, and location-specific. Just because solar farms in Britain are on average expected to enjoy a premium over baseload prices, doesn’t mean that your particular solar farm will. It might be sitting behind a localised transmission constraint which may ensure it is curtailed more often during higher priced periods. If the compensation for curtailment is based on average price, then this remuneration may not be sufficient to compensate.