Sweden is a country proud of its uniqueness. An old local proverb puts is well by saying that “Blott Sverige svenska krusbär har”, or “Only Sweden has Swedish gooseberries”. This applies also to wind power. Sweden is one of the few countries that has implemented a truly market-based cap and trade system to promote renewables, and possibly the only one that has never substantially changed it since it was set up in 2003.
However, since then much has changed in the way wind projects are financed. The market dynamics created serious challenges for the trailblazers, and forced followers to take radically different approaches: ditching long-held assumptions about the way prices move, reversing debt-equity ratios, completely rethinking structures for power sales contracts and drastically reviewing expectations. Ironically for one of Europe’s most stable renewables regulatory regimes, adapting to ever-changing conditions has become a necessity.
Sweden’s Elcertificate system is simple. Supply is created by awarding producers one certificate, a freely tradeable security, for every clean MWh produced over 15 years. Demand comes from pre-determined annual quotas that consumers of electricity must purchase. The market is then left to figure out the rest: there is no floor or cap on prices and no buyer of last resort. “Brown” power sales are also market-based: producers sell on Nordpool (the deepest and most liquid power market in the world) and are free to tap into one of the most advanced markets for PPAs to hedge prices over the long term. The market is king.
This stable, market-based system is one of the key reasons why many investors are attracted to Swedish wind. Others include the country’s pristine AAA rating, business-friendly reputation, strong public support for wind power and relatively benign planning environment.
Thanks to its low population density Sweden has been at the forefront of industrial-scale wind. While developers in France, Germany or the UK are still struggling to promote projects of more than 30MW–40MW, Sweden has now seen triple-digit MW wind farms systematically being built for several years. Although its winds have lower average speeds than Norway’s or Ireland’s, they are constant, i.e. predictable, energy-rich and with low turbulence.
Finally, but perhaps most importantly, Sweden is a place where building wind makes sense from an industrial policy perspective. Its system runs mainly on hydro and nuclear, which together account for more than 80% of power production. The former is fully developed, and the latter is old, expensive to run and being phased out as obsolete. Wind power today is by far the cheapest source of new capacity, and in the future its intermittency at higher penetration levels will be mitigated by the existing flexible hydro fleet, very developed interconnections with Europe and if needed, storage.
Large-scale, low-cost, stable regime, AAA rated country – sounds like an ideal setting for renewables investment, so what’s the catch? Complexity. While Sweden has many very attractive features, the market-based nature of a wind farm’s revenue line makes investing there more complex than in other markets. Sponsors need to take a view on power prices over a period of 25 years, and of Elcertificate prices over 15. Both commodities are highly volatile: all-in revenues for a wind farm were above €50/MWh only three years ago, and are now around €30/ MWh today.
They are also notoriously unpredictable – today’s prices are substantially below past predictions. Many consultancy firms (Markedskraft, Nena, Poyry, Baringa, SKM or Thema to name a few) publish long-term forecasts for Nordic prices, and have widely different views. The spread between their “low” and “high” scenarios is among the highest in Europe. Elcertificate forecasts in particular have been bordering on intellectual speculation.
Add to the mix disruptive change happening in the fossil fuel market, renewables and the broader energy infrastructure, sprinkle with deep uncertainty on future carbon emission prices (if any) and those ideal features of a market-based system quickly blur away.
This often leaves investors analysing the market initially baffled. We regularly get calls from colleagues in other investment firms asking us what price curves we use for Sweden. We usually start by saying “all of them, and none of them”. By this we mean that nobody has a crystal ball to predict how prices will evolve and investors need to properly understand how the range of possible prices interact with the investment structures they get into and be comfortable with the risks involved.
Which leads to what is possibly the most important decision facing investors: how long to hedge prices for. This is where an important feature of the Elcertificate market comes into play. Power can be hedged for up to 10 years on Nordpool, and we recently saw bilateral PPAs with industrial buyers such as Google, Facebook stretching to up to 15 years.
However, a market for long-term EPAs (Elcertficate Purchase Agreements) has failed to develop so far, for two main reasons: the first is that the market is much smaller than Nordpool and illiquid. The second is that the system is set up so that buyers have no incentive to enter into long-term contracts. Elcertificate supply is intrinsically long-term – every new wind farm locks 15 years of certificates in the system – whereas demand is stubbornly focused on the spot market.
This limits the option for investors to short-term EPAs: 15-year contracts have been explored, in fact we started implementing one ourselves before our trading partner got cold feet, but they remain highly dependent on complex structures with scarce, sophisticated intermediaries, post-financial close price risk and heavy liquidity discounts.
The balance of such a system, requiring new build rates to match precisely the shape of the demand quota curve, is very fragile. With the benefit of hindsight an imbalance at some point was inevitable: how that happened and its implications had a big role in shaping how the financing evolved over time.
Expectations vs reality
From the early days approximately up to 2013 investors and lenders (backed by consultants’ analysis) held a view that as part of a cap-and-trade system, Swedish prices should evolve so that over time the sum of power and Elcertificate prices matches the long-term marginal cost of building wind projects, which at the time was in the region of €60MWh–€80/MWh. This view implied that long-term hedging was not needed – saving projects between €1MWh and €2MWh of hedging costs and most importantly leaving projects exposed to upside from rising prices in crunch periods, while keeping the downside protected.
This view shaped the financing of the first large-scale projects. First, equity investors and lenders were happy with short-term hedging contracts: structures with three to five-year contracts for power and just one year for Elcertificates were quite typical. Second, lenders provided non-recourse project financing through similar debt structures to those used for feed-in-tariff regimes, eg,15-year amortising loans covering 65% to 75% of construction costs. In their stress-cases many investors assumed that power and Elcertificate prices would “compensate for each other” as described above.
Finally, several sponsors approached the market with relatively short-term strategies. Together with a boom of financings from smaller, often local investors this fuelled a period of very high rates of new build. In 2010 to 2013 investment decisions averaged 1,000MW per year.
What neither investors, nor lenders, nor expert consultants had considered was how the structural imbalance mentioned earlier would affect the market. The high rates of new build fuelling supply, and the impact of the financial crisis curbing demand created an oversized glut of Elcertificates. If the demand side had an incentive to lock in those low prices by buying certificates in advance (they can be banked indefinitely), this could have quickly rebalanced the market towards the expected costs of wind power. But this didn’t happen, and Elcertificate prices de-coupled from power prices, also on a downward trajectory.
The market entered a phase where total revenues were well below the cost of new build. Hedging power for the long term would make returns quite unattractive, unless investors were ready to believe in a significant uplift in Elcertificate prices. For a while, experts kept calling an upcoming surge in these, but that never happened. Some wind farms were financed in 2014–15 but at a rate of about 300MW per year, more than three times lower than during 2010–13.
Then, from early 2016, things started to change, and in that year the pace picked up with close to 1GW financed again. The flow of private capital also picked up, but this time with radically different financial solutions.
How the approach of investors changed
It is fascinating to see how – even if the system has been virtually unchanged for a very long time – the approach to investing went through a profound transformation.
Technology is possibly the most important driver of this new wave. Aware that the age of subsidies is almost over, turbine manufacturers had been working hard at reducing total costs throughout their entire supply chain. Some – Vestas in particular – also developed turbine models that fit very well with Sweden’s wind regime and planning environment: very large rotors to capture more energy in Class III sites, and bigger towers to tap into stronger winds at higher altitudes. This has led to a reduction in the cost of producing 1MWh of about 30% since 2010 – almost matching the drop in revenues.
The market started focusing on larger and more efficient projects – discerning these from the pile of permitted sub-scale projects with mediocre resources. We wrote a paper back in 2014 warning investors about these inefficient “zombie projects”, and about the need to focus on the most efficient projects to avoid aggravating the certificate surplus.
The type of investors and structures also changed. Large financial institutions with long-term holding horizons such as insurance companies and pension funds, eg, Allianz, MunichRE, APG, or long-term funds, eg Blackrock, have been the main source of private capital. These have almost systematically avoided the use of project debt in their financings –a very logical choice in this market.
Banks, in fact, also learned the lessons from the early years and started requiring much higher levels of contracted revenues for projects. For example, they would require a standard coverage ratio of 1.2x for contracted revenues, but a much higher one for uncontracted ones, as well as using much more conservative assumptions for the latter. This limited the amount of debt that a project could raise.
If an equity investor also uses more conservative assumptions for prices, the expected base case IRR is lower and the benefits of leverage quickly wane while all the costs, the governance restrictions and related risks remain.
Finally, investors also changed their approach by locking in power prices for longer periods. We saw the emergence of direct corporate PPAs for very long terms, 10 to 15 years post financial close have become typical. Elcert risk still stays, but we also saw solutions where this was transferred to the developer through earnouts or similar structures.
So investors showed a clear sign of better understanding the market: still buying into the thesis for Swedish wind power, but accepting the uncertainty on power prices, mitigating it with long PPAs and no project debt. So if an early investor was aiming for a 13% levered IRR on a “base case”, but really facing a loss of its equity in case of a severe drop in prices, today’s investors are aiming at a 7%–8% unlevered return using more conservative assumptions, with a downside case of getting a 3%–4% IRR in a long-term bearish scenario.
On balance, so far, the Swedish system can be called a policy success: it enabled the country to reach its targets for new clean power a few years ahead of schedule and at the lowest cost to consumers in Europe on a per MWh basis. It also succeeded in slowing down the pace of new construction when this was too high, and in pushing hard suppliers of equipment, development work and capital to find solutions to drastically reduce their costs – all through market forces alone, with no direct intervention.
Other countries in Europe such as Spain and Italy adopted much more aggressive measures to correct new-build excesses, disrupting their systems and retroactively taking away tariffs they had explicitly promised to investors and are fighting these in court.
This success is not distributed evenly: early entrants in the Swedish market are the ones who paid the heftier price for this success: they enabled the system to take off, and the projects they financed enabled the technological platforms upon which todays’ much more efficient projects are based on.
However, they are now locked in assets with a replacement value that is lower than their debts. In contrast, earlier investors in feed-in tariff systems are usually protected from market imbalances and competition from newer, lower-cost entrants. It will be interesting to see how the market will now deal with this fleet of “legacy” assets. Over the next years, we are likely to see more large-scale – from 150MW– 200MW upwards – new projects financed by blue-chip names. We are also likely to see more advanced corporate PPA solutions with new entrants, and maybe also some creative solutions on EPAs that could bring debt financing back in some projects.
Some big questions on the horizon: How cheap can wind power be? What impact will this have on demand? And on the nuclear power phaseout? How will the Swedish system react to a functioning ETS market? Whatever the course of events, it is likely that Sweden will keep its approach and let the market figure itself out. After all, sticking to that particular type of gooseberries has worked well so far for its consumers.
(Published in September 2017 on Project Finance International)