The last year and a half hasn’t been particularly kind to forecasters. The failures across various recent elections by political pollsters to spot surprise victories (think Brexit, Trump) has cast doubt on the ability of polling companies’ previously tried-and-trusted methods. While the spotlight is likely to escape forecasters in the power markets, it is possible they might also be grappling with the rapidly changing nature of their own industry.
Critical to asset management and investment decisions in the market are the power-price forecasts provided by experts for the short, medium and long term. These are influenced by a range of factors including policies, commodity prices and previous investment decisions, with different issues carrying varying weight the longer into the future.
Built upon principles of supply and demand, the forecasts model demand for electricity in specific markets and adjust accordingly, factoring in GDP movements and decarbonisation targets.
Certainly, for much of the UK and the rest of Europe, the experts providing these views mostly come from two leading consultants – Finland-headquartered Poyry and UK-based Baringa – with the result being that much of the industry is provided with their power price projections as they try to continuously adapt to the ever-changing energy market.
The forecasters’ advice is fed into asset managers’ portfolios, tilting valuations either upwards or downwards depending on the scenario, although project owners are warned not to take forecasts as gospel.
“We don’t have a crystal ball,” cautions Ali Lloyd, senior principal consultant for Poyry in London. “Our role in the market is to provide independent views of what prices might be in the long term to help investors make their decisions. We have a good understanding of how energy prices work and are driven by the underlying economic fundamentals. We use that knowledge to project what could happen in the future.”
It is a position that is reiterated by Baringa’s Phil Grant, partner in the firm’s energy and resources team.
“The role of a market advisor is partly in doing the analysis, but equally in making sure the explanation of results is very clear to clients to make sure they understand the implications of our analysis and the risks they’re taking when they make decisions off the back of it,” he says.
LIVING WITH A FLATTER CURVE
It is the risk factor that Grant speaks of which is beginning to enter new realms, particularly for a sector that was perceived as insulated from the messy world of power price fluctuations: renewables.
Subsidy-backed renewables were historically seen as the low-risk option for energy infrastructure investment, with their limited exposure to wholesale power prices providing stable, visible revenue streams.
That was then. The now is a picture where vast amounts of European renewables over the coming years will be exposed to merchant power risk, for example, through the 8GW of renewable power awarded in Spain this past summer, subsidy-free offshore wind secured in Germany and expired ROC-accredited projects or new-builds in the UK.
Part of the problem with the current picture is that power prices – excepting for periods of market volatility – have stayed stubbornly low, with assets generating fewer revenues as a result. The usual counter to those fears is that the general long-term forecasts predict an increase in prices based on a continued demand for gas.
“Our central view is [that], in the long-term, gas prices will rise in Europe as the North Sea gets depleted [and] that gas has to come from further afield to meet what we think is a fairly stable demand for gas,” Lloyd says. “In our central scenario, that’s what happens. In our low scenario, that doesn’t happen and there are other scenarios where it doesn’t happen. There is genuine uncertainty in the future and clients should understand there is a wide range of possible outcomes.”
That view is shared by Grant at Baringa, although he adds that this effect is offset somewhat by the growth of low-cost, merchant renewables.
“Our central scenario for the European market at the moment is [prices] gently rising in real terms driven by a combination of commodity prices, capacity margins and the impact of the rising carbon price,” he says. “The latter is predicated on the continued efforts to decarbonise across European and global energy markets.”
But what if the future is made up of a flatter power-price curve?
Bloomberg New Energy Finance, the relatively new kid on the block focusing on a smaller number of markets in Europe, envisages a lower-cost, flatter view, presenting challenges for future investment.
“Going forward in time, you are less and less influenced by gas prices because you get more renewables and this disengages your price,” explains Andreas Gandolfo, European power analyst at BNEF. “We're not seeing significant rises in prices. In real terms, we're looking at something that looks very flat. Wind and solar prices have come down very aggressively over the last few years and this creates a question of how you invest in what is a practically static, if not shrinking, market, which is the case for Europe. Even if you see power prices trending up, these are realities that you still need to grapple with. These are dynamics that will affect Europe and a few technologies.”
BNEF is not the only firm thinking lower prices are here to stay. A report from EY last year noted the major European utilities have come to the “belated acknowledgement” of energy commodity prices being “lower for longer”.
“To what extent do you think it’s possible to predict the future of power prices?” asks Giles Clark, former chief executive of private equity-backed developer Primrose Solar (now wound down) and currently an industry consultant at AlSi Consulting. “That’s the fundamental underlying challenge, and the answer is it’s very difficult because it’s based upon an enormous number of variables and because the market is heavily influenced by government intervention.
“I suspect forecasters are systematically overestimating the underlying cost of generating electricity in the long term, as advances in technology reduce costs. Wholesale price is a blended figure and when I started looking at large-scale solar in the UK five years ago, solar could show a premium over the average. Electricity from solar farms is now sold at a discount to the average wholesale price. My feeling is that energy in the long term will be cheaper.”
This volatility in prices and the divergence of views among forecasters exist not just in long-term projections, but also in short-term ones and led to a change in strategy for at least one asset owner.
London-listed Bluefield Solar Income Fund, which owns 425MW of UK solar assets, began after its IPO in 2013 by using one “leading independent” forecaster, an approach it said was “considered to be the purist way” to apply forecast valuations to the portfolio. But the fund became aware of a discrepancy in the results of its chosen forecaster and the other market leader – caused by differences in timing and methodology – which was causing a £19.9 million ($27 million; €22.6 million) fluctuation in the fund’s discounted cashflow valuation.
“In the very short-term calculations there was quite a big gap,” says James Armstrong, managing partner at Bluefield. “There was a fairly big and consistent difference in the first years because of a different methodology being adopted, so we thought it was appropriate for our shareholders that we should have an equal blend of the two.”
Like others, Armstrong and Bluefield take the long-term view that additional renewables added to the grid, as well as more expensive gas to replace falling European supplies, will help push power prices up.
At German investment manager KGAL, the expectation of a rise in long-term prices draws from chosen consultant Poyry’s analysis of a convergence across the energy sector, which will also include rising demand for heat and transport sources. That said, the firm looks to stay on the more cautious side of estimations.
“If we can be more conservative on certain assumptions, be it lifetime, power curves, yield profile, and still getting access to a deal, then that’s good for us,” says Michael Ebner, KGAL’s head of infrastructure. However, he maintains the company consistently tries to avoid merchant power risk in a variety of ways, with all the projects across its four renewable energy funds backed by feed-in tariffs.
“Although the power price is expected to rise over the next 15 to 20 years, it’s still a matter of securing revenue streams and stabilising them,” adds Ebner.
There are, of course, alternatives to the widely used Poyry, Baringa and BNEF models and in some cases they come free of charge. At Primrose Solar, Clark says the company would use Poyry and Baringa at different times, but would also look at the forecasts supplied by the UK government’s energy department, although these did not cover prices in different months or different times of day.
“Annual wholesale electricity price forecasts published by BEIS/DECC have tended to be more closely aligned with the actual outcomes in recent years,” he explains.
Nevertheless, regardless of the forecaster used, Clark acknowledges the risks posed by renewables projects in a low-power price future, despite the more attractive conditions available now.
“The challenge for asset owners is that these are long-term infrastructure assets,” he says. “The ROC-side of the revenue is considered to be very predictable, linked to inflation and thus extremely attractive to pension funds. The other side of the revenue stream is entirely exposed to UK wholesale electricity prices and significantly less attractive to long-term, low-yield investors. There’s a mismatch between the two.”
Clark suggests that part of the solution may lie in the corporate power purchase agreement market, a fixed-price, revenue-securing model that has taken off with technology giants such as Apple and Google in the US, although it remains relatively nascent in the UK and European markets.
CHANGE, CHANGE, CHANGE
The challenge faced by both investors and the forecasters is the rate of change in the market in terms of both prices and technology.
The UK’s recent Contract for Difference auction, for example, took the entire energy industry by surprise after offshore wind projects set to be installed by 2022-23 scored a 50 percent reduction on prices from two years ago, down to £57.50 ($76; €63.30) per MWh (see p. 4). Such reductions were “unprecedented for large energy infrastructure”, according to the industry’s trade body RenewableUK, although the projects will face merchant power risk once the 15-year fixed price expires.
“I don’t think forecasters’ models are particularly good at capturing the impact of disruptive change,” Clark asserts. “I doubt any forecaster over the last decade has taken into account the rate at which the cost of generating from renewables has fallen. If you believe solar and wind will keep getting cheaper, then a lot of these forecasts are likely to be wrong.”
Yet the forecasters are trying to keep their heads above the parapet as new technology begins to enter the fray. Once a pipe dream, the UK expects about 550MW of energy storage to come online by 2020.
Lloyd says that Poyry is analysing energy storage’s prospects and its impact on the system, but this can be difficult with an innovation that seems to be exceeding itself constantly.
“We are looking at storage and taking views on how much battery capacity can be deployed,” he says. “One of the challenges of these projections is we're having to take views on technology cost evolution as well. Costs continue to come down and we're having to take views on how quickly they will come down and how quickly they'll be deployed.”
As renewables become more exposed to an increasingly unpredictable power-price curve, investors need to reassess the sector’s risk profile. Failure to do so might see them waking up late to a much riskier long-term reality.