The power markets in which Statkraft operates reflect the general global economic development; a mature European market with low growth, and immature Emerging Markets with high growth.
Although there are differing policy responses and price developments in the various markets, they are influenced by some common global trends:
- High fuel prices. The prices for global fuels (oil, gas and coal) are significantly higher than 10 years ago, and the forward markets indicate that they should remain high due to Asian demand growth.
- Climate change. Significant measures must be put in place to reduce global CO2 emissions to 1990-level (see figure below). As the energy sector accounts for more than two-thirds of global greenhouse-gas emissions, its participation in reducing the carbon footprint is crucial in order to tackle the climate change.
- Cost reduction of solar and other renewable energy sources. The cost for solar photovoltaic (PV) panels was reduced with more than 80% between 2006 and 20121). While large scale deployment is driven by support schemes, mainly in Germany, Italy and Japan, further cost reductions will lead to solar reaching grid parity in the years to come. In addition, as the cost of distributed resources is brought down, small scale distributed solutions may emerge ensuring a sufficient level of security of supply in Emerging Markets. Its full impact on the power systems remains to be discovered.
The power markets in Europe are all influenced by three major trends: Firstly, the demand development is flat, and forecasts indicate that the demand levels from 2007/2008 will not be reached again until around 2020. Secondly, the EU targets for increasing the share of renewable power sources in the energy mix have led to support schemes being established across Europe. This has caused a significant influx of new renewable generation into markets with stagnant demand growth, leading to less need for conventional generation sources. Thirdly, these two trends in combination with reduced growth in the wake of the financial crisis should allow for EU to reach its targets for reducing emissions in 2020; hence the price for CO2 emission allowances has collapsed and will remain at a low level unless major reforms are put into place or new binding targets are set for 2030.
Depending on the choice of political carbon footprint reduction measures and the market structure, these major trends have impacted the European countries in different ways. Each of the countries that Statkraft operate in, or plan to operate in, are described below:
The Nordics; focus on Norway and Sweden
The Nordic power market has successfully been deregulated, and was fully integrated when Denmark became a member in 2000. In 2005 Germany was included via Kontek2) bidding area. In 2009 market coupling of 11 European countries was launched through EMCC (European Market Coupling Company) by Nord Pool Spot and EEX3), and Estonia and Lithuania were included in 2010 and 2012, respectively. The wholesale market is trusted by market participants, regulators and politicians. It enables optimal production planning for generators and allows for an active end-user market with significant customer choice and movement.
In 2012, the common green electricity certificate (Elcert) scheme was launched. This is a marked-based support scheme introduced to promote renewable power generation in Norway and Sweden. Under this scheme, Norway and Sweden have a common goal of introducing 26.4 TWh new renewable generation within 2020. Producers get one certificate for each MWh of electricity generated from new eligible renewable sources for 15 years and suppliers are obliged to buy a certain amount of certificates. This market is in general viewed as successful, and so far has managed to deliver new renewable generation as planned.
The Norwegian-Swedish Elcert market, combined with Finish and Danish support mechanisms for new renewable energy sources and a new nuclear reactor in Finland, will lead to a significant energy surplus4) in the Nordic electricity market towards 2020. In a region where hydropower, nuclear and eventually wind and other renewable sources constitute more than 90% of the production mix, the surplus is likely to lead to lower wholesale prices, unless the power is exported. This again remains dependent on transmission capabilities to adjacent markets and corresponding power prices. Nordic prices are thus highly dependent on the development in the surrounding markets, and the number of new interconnections being built. There are specific plans for increasing the interconnections by 82% between now and 2020, and further interconnection projects are expected to be developed and realised after 2020.
The German electricity market is heavily influenced by “Energiewende”, which is a policy term describing the move away from nuclear power and the decarbonisation of the German electricity production. The growth in wind and solar installations in Germany has been exponential over the last years, making Germany the leading country in the world when it comes to solar installations, with almost one third of the global solar capacity. The combination of this growth and flat energy demand growth result in a significantly reduced need for conventional thermal generation. In addition, solar power output at its maximum in the middle of the day, during what used to be high priced mid-day hours on workdays. As a result of the large influx of power from renewable sources, the conventional thermal power plants in Germany has seen a dramatic change in their operating conditions, and a large portion of German flexible coal and gas fired generation is currently not able to generate enough income to cover running cash costs, i.e. negative returns on capital.
In principle, this means that these plants should be mothballed or closed. However, since solar and wind are intermittent energy sources and sufficient storage capacities are not developed, the security of supply could be reduced to an unacceptably low level. Thus German authorities have put in place a law forbidding plants that are deemed to be system relevant to close. This law is expected to be followed by a more permanent capacity remuneration mechanism (CRM) ensuring that plants that are needed for the system stability will be sufficiently remunerated.
This capacity mechanism is a major market design change, which is believed to be needed in most European countries as the share of intermittent power increases. Reflecting these developments, the German wholesale power prices have been falling. However there is considerable possible upside if the CO2 price in the European emissions trading system (ETS) or a similar CO2 tax increases.
The French market is mainly supplied by nuclear and hydropower. While there is some debate on nuclear policy, France seems set to keep the nuclear capacity intact. France is also increasing its renewable energy deployment, although at a slower pace and with less ambitious goals than neighbouring Germany. However, the lack of flexibility provided by the nuclear power fleet, along with reduced flexibility from neighbouring countries, results in the need for a CRM also in France. A first design has already been proposed by the authorities. There might also be a good possibility of demand side participation in these capacity markets.
A large portion of the UK’s coal plants, along some gas plants are set to close due to EU directives5) on direct pollution (and not on climate policies). This puts the UK in a situation where there is a potential lack of capacity in the next few years. The British authorities have for many years supported an increased deployment of renewable energy sources, but due to inefficient planning and grid constraints, they have not reached their ambitious goals. Still, the UK has more offshore wind installed than the rest of the world combined. In addition, the government wants to develop new nuclear installations to replace old ones being decommissioned at the end of their technical lifetime. However, neither of these generation technologies offers flexibility; hence a CRM design is under discussion also in the UK.
In 2010, the UK launched a certificate and quota scheme – the Renewables Obligation – as its main incentive scheme for renewable generation capacity. Each technology earns a certain number of Renewable Obligation Certificates (ROCs) per MWh produced for 20 years, e.g. 0.9 ROCs/MWh for onshore wind and 2 ROCs/MWh for offshore wind commissioned in 2013/14. The value of ROCs was £46/MWh in 2013. Between 2104 and 2017, the Renewables Obligation will be replaced by, a feed-in tariff with contract for difference (CfD) under the Electricity Market Reform. The CfDs offer a stable price for renewable generation, collected via a top-up payment on the market price to a set technology specific "strike price". In this scheme, for investments made in 2014-2017, onshore and offshore wind power producers are granted an income of £95/MWh and £155/MWh, respectively, for 15 years. The tariffs are reduced to £90/MWh and £140/MWh for investments made after 2017.
Currently the UK also has a unilateral so-called carbon price floor, setting a minimum price for CO2 emissions. This leads to a significantly higher marginal cost for gas and coal fired generation and thus also higher prices in the wholesale market. While there seems to be a strong political commitment to the carbon price floor, it is uncertain to which extent the UK would choose to retain it if ETS is abandoned or remains at the low levels seen today.
Albania has a power consumption of 6-7 TWh/year, which corresponds to the production from Statkraft’s hydropower complex Ulla-Førre. It is a small market, due to a small population and a slow economic development. The market in Albania is currently moving towards deregulation, but it will still take time before there is a functioning market available for generators, retailers and consumers.
Due to the ongoing regionally coordinated market liberalization and the integration with surrounding markets, Albania needs to be seen together with its neighbouring countries when assessing the market attractiveness. The Balkan region has seen some economic growth in the recent years, and although there was a setback after the financial crisis, this is expected to lead to increased energy demand in the region in the years to come. Even if the renewable power deployment will increase, continued demand growth will prevent the market from developing into the situation that is currently challenging Germany and North Western Europe. The liberalization of the power market is expected to gradually lead to cost-reflective wholesale prices, even if its timing and success is uncertain.
The Turkish power market is slightly above 200 TWh/year. It has undergone a liberalization process during the last decade, as generation, transmission and end user supply have been unbundled. In August 2006 a balance and settlement market (BSM) was in place and in December 2011 a power exchange similar to the Nordic exchange with a day-ahead market was established. The demand growth in Turkey has historically been strong, and while there is some discussion on the pace of growth going forward, the population growth and economic development are likely to lead to a growing electricity demand in the upcoming years.
Turkey is currently not committed to any compulsory CO2 emission reduction targets. The future CO2 regulation is uncertain, and depends on future international commitments as well as the relation to the EU and the Turkish preferences for market based solutions versus more direct regulations. In the case of a CO2 market, implementation before 2020 is unlikely.
Due to the strong historic growth, power prices have been high, and a large number of power plants are under construction and will be commissioned over the next few years. However, a reduced growth in the years to come could cause the prices to drop. In addition, the solar PV cost reductions, the development of fuel prices and the extent to which Turkey adopts a CO2 price regime will be determining for the price development. Turkey is well suited for distributed solar PV; as the sun conditions are good, and the demand profile is fitting the generation pattern. This is expected to increase security of supply as local grid congestions can be avoided.
Emerging markets are defined as markets where social or business activity is in the process of rapid growth and industrialisation. All countries in which Statkraft operate outside of Europe can be described as emerging markets.
For emerging markets the main underlying driver is continued population and economic growth, which in turn drive energy demand as the various countries develop. Statkraft expects strong power demand growth in most emerging markets where the Group is present, and significant increases in renewable energy deployment is expected for emerging economies on every continent for the decades to come (see graph). It should be noted that many emerging markets have fundamentally different challenges when it comes to the maturity of the economy, effectiveness of governmental institutions and the power market design. Economic growth will depend on how these countries manage a trajectory towards becoming medium to high income economies.
Two main uncertainties in these markets – besides fossil fuel prices – are (i) at what time the individual countries will reach a state where the power markets are open, competitive and well-functioning with supply and demand in balance and (ii) how solar PV could impact demand growth for central generation. The latter is particularly relevant as most of these countries lie in sunny areas.
In some markets distributed solar PV could potentially be a game changer and significantly impact overall demand growth from central power production. As infrastructure is not keeping pace with demand growth, more distributed solutions could be put into place to ensure power supply at a decreasing cost.
While each of the countries is very different in structure, nature and degree of development, they all share a need for new power production as demand is increasing. This again means that investors must see a future revenue stream that will pay them a reasonable, risk-adjusted return on their investment. While market design differs from country to country, in general it means that prices in these markets over time must be at a level covering both full operating expenses and capital costs for new efficient power plants.
India is a large market (990 TWh/yr) with a high growth rate and large long-term potential for developing hydropower. There are, however, potential risks in such a diversified and complex market, with many regulatory entanglements, current market distortions and risks related to business conduct and licensing. In the longer term, further economic growth, reforms and continued market liberalization are expected, hence increasing the attractiveness for investments in renewable energy.
Economic growth has driven demand growth strongly in India for the last decade. Increased household income in combination with rural electrification and industrialization is expected to maintain the growth levels at a high level going forward.
The Indian electricity market has experienced a large capacity growth during the last two years, dominated by coal-fired plants fuelled by cheap domestic coal. However, the rate of investment in new capacity is expected to decrease, and the current overcapacity can be viewed as cyclical. Price regions within India have emerged, with moderate prices in the northern and high prices in the southern grid.
The liberalization process of the Indian power market is expected to continue. Domestic gas and coal prices, which are currently at a low level, are expected to slowly move towards higher levels, reflecting more the import parity levels of the different fuel segments. The Indian distribution sector is currently under financial stress, with low regulated end user tariffs and high losses. In the current market, their financial situation is influencing the ability and willingness to pay for electricity, which is further dampening the wholesale price levels. Further economic growth and reforms within the distribution sector are expected to gradually improve the willingness to pay, thus having a net positive effect on the merchant prices going forward.
Brazil has a large domestic power market, with a total demand of 500 TWh in 2012. The annual demand growth since 2000 has been around 4.4 percent, and although a current slowdown in economic growth is expected to stall the demand growth the next couple of years, an underlying long-term growth is expected going forward.
The Brazilian power market is a regulated market with strong emphasis on security of supply and the planning role of the state. Investments in new capacity are licensed through national auctions in the regulated market. Installed capacity as of today is dominated by hydropower. Going forward, hydropower is still expected to play an important role, with a large remaining potential. Wind power has emerged as a cost efficient technology given favorable wind conditions in the north-east, and is expected to play an increasing role in the future capacity mix.
Brazil has a defined regulatory system, however it is highly politicized and thereby subject to changes and regulatory risk over time. The end of 2012 and 2013 has been characterized by drought and low inflow of water, which has put severe stress on the power system. The entire thermal generation stack including oil and diesel has been defined as “must run”. A high focus on security of supply in a largely hydro-dominated system has given a high level of expensive thermal generation outside of the merit order6) which again has resulted in a high burden on the consumers. Regulatory changes were introduced in the spring of 2013, formally incorporating this discretionary dispatch in the market price formation, and thus representing the risk aversion for not obtaining security of supply in dry weather scenarios. The impact on spot prices is still uncertain, but is expected to increase spot prices on average.
At the same time the latest price development in auctions has shown a highly competitive market, with decreasing price levels for power purchase agreements (PPA). Small scale hydro and wind has still proven competitive in the two last regulated auctions.
Whole sales electricity prices in Chile are among the highest in Latin America and higher than the OECD average. The market design is liberal and stable. Transmission constraints and price area differences can potentially be an increasing challenge - or future opportunity for the market players.
The average demand growth in the main system SIC7) (46 TWh/yr) from 2000 to 2007 was about 6% per year. Going forward a steady demand growth is expected. In order to satisfy this increasing power demand, Chile needs to almost double the installed capacity over the next ten years.
Chile has a liberal and stable regulatory framework that stimulates private investments. This has lead to a highly competitive market with a few dominating players. The market is characterized by a high degree of private capital; hence capacity expansion relies solely on market based investment decisions subject to environmental approval and permits granted.
During the last years, a growing awareness of environmental impacts and flagging of social and civil rights have resulted in public opposition and protests towards power projects, making it more challenging to build new capacity and modify existing plants.
Conditions for solar technologies are viewed as favorable in particular in the northern part of Chile. However, current lack of financing availability and political support may limit the development. Measures introduced by the government during 2013 are aiming at reducing the current obstacles facing developers, and the risk should diminish over time.
New transmission lines have also faced delays and have not been able to be built and commisioned as planned. Going forward, lack of timely investments in the grid can cause increased differences in area prices, influence grid stability, and also limit the potential sites for new capacity.
Peru has a stable and growing economy. Going forward, growth in demand from the current level of 37 TWh/yr is expected to be considerable. The main driver for increased electricity demand in the medium-term is increased activity in the mining sector.
Until year 2000 the Peruvian power system was predominantly a hydropower system with only modest use of natural gas and fuel oil for power generation. The discovery of large domestic gas resources, low politically set gas prices and subsidized gas transport costs have spurred the development of gas-fired plants, and today gas-fired plants account for more than half of the total installed capacity for electricity generation.
Low spot prices make capital intensive investments in Peru dependent on a viable long-term PPA’s. The state has introduced specific rules which favor hydropower projects in mandatory procurement for power from distribution companies. The PPA received for the Cheves hydropower project, currently under construction by SN Power, was a result of such a tender process.
1) Bloomberg Energy Finance BNEF.
2) The Kontek HVDC is a 170-kilometre (110 mi) long, monopolar 400 kV high-voltage direct current cable between Germany and the Danish island Zealand.
3) EEX, European Energy Exchange, similar to the NordPool trading platform.
4) Surplus = Production – demand, i.e. more production than there is demand.
5) Large Combustible Plants Directive and Industrial Emissions Directive.
6) The merit order is a way of ranking available sources of electrical generation, in ascending order of their short-run marginal costs of production, so that those with the lowest marginal costs are the first ones to be brought online to meet demand, and the plants with the highest marginal costs are the last to be brought on line.
7) There are four different electricity systems in Chile. SIC, the Central Interconnected System, which serves the central part of the country (75.8% of the total installed capacity and 93% of the population). The long distances existing among the four systems make their integration difficult.