Market and framework conditions
The energy markets Statkraft participates in follow the same trends as the general global economic development; a mature European market characterised by low growth, and emerging markets with more vigorous growth. However, growth in emerging markets has slowed in recent years compared with what we have seen previously.
While policy mechanisms and price development vary among the various markets, they are all subject to the same global trends:
- Uncertain fuel prices. Global fuel prices (oil, gas and coal) have dropped significantly during 2015, which was also the case in 2014. Oil prices in late December were down by more than 60% compared with their highest level in 2014. No matter what the cause of this decline, it has led to a more pronounced general perception of uncertainty surrounding future fuel prices, accompanied by more uncertainty as regards investments in the energy sector.
- Climate Change. Heat records have been set in 18 of the last 19 years. In November 2015, the World Meteorological Organization (WMO) reported that 2015 will probably be the hottest on record. On average, global temperatures have increased by 1 degree since the pre-industrial age. As many as 195 countries gathered in Paris to endorse a climate agreement which lays out plans for reducing greenhouse gas emissions from each of these countries, as well as a pledge to meet again every five years to pursue more ambitious plans. As the energy sector contributes more than two-thirds of global greenhouse gas emissions, it is essential that the sector does its part to bring about reductions.
- Lower costs in solar and wind energy. Costs continue to fall for photovoltaic solar panels. Subsidies have been the driving force behind large-scale development of solar and wind power up to now, primarily in China, Germany, Italy, the US and Japan. Now, however, both solar and wind power are competitive in a number of global markets, even without subsidies.
- Increased potential for distributed solutions. Declining costs for small-scale power production and storage (batteries), along with the emergence of technical solutions for distributed systems, provide opportunities for effective further development of the power sector in emerging markets. It also provides the possibility of transitioning to cleaner power generation in Europe and around the world. Batteries are also being used more frequently in other types of balancing services.
The illustration below shows the IEA's forecast growth in use of primary energy and associated carbon emissions from the most recent World Energy Outlook, WEO 2015. Starting from last year, expected primary energy consumption in 2035 has been reduced by approx. 2%.
The growth is unevenly distributed, and forecasts indicate that the OECD will experience real decline in primary energy consumption. The OECD will account for a lower percentage (-4%) of primary energy demand in 2040 than in 2013. This is a change in relation to last year when the OECD's share increased by 3%.
The power markets in Europe are impacted by two strong trends: The first is stagnating demand, due in part to repercussions after the financial crisis, in part to phase-out of industry and transition to more service activities and in part to energy efficiency measures. Forecasts indicate that demand will not rebound to 2007/2008 levels until 2020. The second is that the EU's objective of a larger share of renewables in the energy supply mix has led to the establishment of subsidy schemes all across Europe. This has led to considerable new renewable capacity in markets where demand has stagnated, and thus less need for production from conventional energy sources. An aging thermal power plant stack in Europe has declining running time and weak profitability. One result of these two trends combined appears to be that the EU will exceed its emission reduction objectives for 2020. This means that the price of carbon emission quotas has collapsed, and may remain low for quite some time.
The EU adopted a climate package in late 2014 with ambitious emission reduction targets by 2030. The package includes energy efficiency targets (-27%), development of renewable energy (27%) and emissions of CO2 (-40%), with an intensification of EU ETS (Emission Trading Scheme) as the policy instrument. In this connection, the EU introduced a Market Stability Reserve (MSR) in 2015. The scheme will take effect in 2019. Both of these decisions are expected to lift the price of emission quotas somewhat in the time ahead.
The Commission presented its "summer package" in July, and regards this as an important milestone in a direction where focus is on the customer, where the energy system will be transitioned to a larger degree of distributed energy, and where the internal market will be realised. The "Package" also contained market design concepts where issues such as integration of RES, more small-scale production and the demand side activities all received attention. The "Package" also contained a proposed directive for ETS which will now be negotiated in the Parliament and the Council. The final formulation is expected in the last half of 2016.
The Commission issued its first "State of the Energy Union" report in November. The report advises member states on how to achieve the "Energy Union", and how to set up plans for achieving the 2030 goals. The report also sums up the status in relation to the 2020 targets; the EU is on track to exceed the emission goals (23%), it is on its way to fulfilling the RES goals, but it seems unlikely that they will reach the energy efficiency target (trend 17.6%). While the EU overall is on track to exceed emission and RES goals, both the UK and the Netherlands are lagging behind in terms of the interim goals for 2013/2014.
Nordic countries; focus on Norway and Sweden
The power market in the Nordic region has undergone a successful deregulation. In 2009, Nord Pool Spot and EEX (European Energy Exchange) introduced market coupling in 11 European countries through EMCC (European Market Coupling Company). Estonia and Lithuania were included in 2010 and 2012, respectively.
A joint green energy certificate scheme (Elcert) was launched in 2012. This is a market-based subsidy scheme aimed at promoting renewable energy production in Norway and Sweden. Using this scheme, Norway and Sweden have a shared objective of achieving 26.4 TWh new renewable production by 2020. Electricity producers receive one certificate for each MWh of electricity they produce from new sources of renewable energy for 15 years, and suppliers must purchase a specific number of certificates.
The Norwegian-Swedish Elcert market, combined with Finnish and Danish subsidy schemes for new renewable energy sources and a new nuclear reactor in Finland, will lead to a significant energy surplus in the Nordic electricity market up to 2020. This comes in spite of the approved shutdown of four nuclear power reactors in Sweden by 2020. In a region where hydropower, nuclear power and potential wind and other renewable sources account for more than 90% of production, the surplus will most likely lead to lower wholesale prices, unless the power can be exported. This depends, in turn, on transmission capacity to nearby markets and comparable power prices. Nordic prices are thus highly dependent on the development in surrounding markets, and the number of new international interconnectors that are built. Concrete plans are in place to boost international capacity by 50% between now and 2025, and it is expected that additional connection projects will be developed and realised after 2025.
Sweden has appointed an energy commission with the stated objective of arriving at a non-partisan agreement regarding the principles that will shape future energy policy. This creates uncertainty surrounding future energy supplies. The process could lead to changes in both the valuation of various power sales, principles for future subsidy schemes for renewable power and energy efficiency assumptions. Both politicians and energy sector organisations are discussing different perspectives for the design of the future energy market. The ultimate result of the energy commission could potentially have a major impact on Statkraft's activity both in Sweden and throughout the entire Nordic region.
The German electricity market is greatly impacted by “Energiewende”, a political term describing the process away from nuclear power and the decarbonisation of German electricity production. As one of the measures under Energiewende, Germany introduced a feed-in tariff for renewable electricity generation (EEG), which led to robust growth in the development of wind and solar power plants and secured Germany the position as the world's largest market for photovoltaic cells (PV) up to 2012. Annual growth after 2012 has been substantially reduced. Annual growth in other markets, particularly China, is strong despite the fact that it was also lower here in 2014 than in 2013. Nonetheless, Germany still has the world's largest installed PV population, representing 21.2% of global installed capacity.
The combination of growth in renewable capacity and flat energy demand has resulted in a significantly lower need for conventional thermal production. In addition, solar power production is highest in the middle of the day, when the price has traditionally been highest. As a consequence of the solid increase in power from renewable sources, conventional thermal power plants in Germany have experienced dramatic changes in their operating conditions. Today, much of the German flexible power production from gas and coal struggles to cover its current capital expenditures; in other words, a negative return on investments.
In principle, this should mean that these power plants should either be mothballed or shut down permanently. However, as solar energy and wind yield uneven production and there is no current solution to the storage capacity issue, this would have reduced supply security to an unacceptable level. For this reason, the German authorities have introduced a law banning system-critical power plants from shutting down. There is significant uncertainty surrounding the closing of thermal power plants.
The German government adopted extensive power market reforms in November 2015. The reformed "Power Market 2.0" entails that no capacity market will be introduced, and thus presumes that supply security is achieved through a pure wholesale market and various back-up capacity reserves. The authorities state that they will not intervene, even if prices should become very high. The intention is that this will stimulate investments in flexible capacity, load management and storage capacity. The strategic reserve mechanism will be extended to after 2017, after the grid reinforcement projects have been completed. A capacity reserve of 5% of maximum load has also been adopted until further notice, as well as a dedicated reserve for 2.7 GW older lignite plants that are to be phased out of the market and shut down. These reserves cannot take part in the market. The market reform also contains items related to the introduction of digitisation, requirements for smart metres and data security. The reforms must be considered by the Parliament, where the Government holds a majority.
Many of the UK's coal power plants, as well as some gas power plants, will be shut down as a result of EU directives banning direct pollution (not climate measures). This creates a situation where the United Kingdom could experience a capacity deficit over the next few years. The British authorities have supported development of renewable energy sources for many years, but time-consuming planning and transmission constraints have prevented achievement of these ambitious goals. In spite of this, the United Kingdom has installed more offshore wind power than the rest of the world combined. The authorities want to develop new nuclear power plants to replace power plants nearing the end of their technical lifetime. Neither renewables nor nuclear power are regarded as flexible production technologies; a fact which has led to the introduction of a capacity market in the United Kingdom.
In 2010, the UK launched a certificate and quota system - the Renewables Obligation – as its primary incentive system for renewable power generation. Between 2014 and 2017, as part of the British electricity market reform, ROC will be replaced by a system of CfDs, Contracts for Difference, which ensure a stable price for renewable power generation. The renewable power producers will receive a supplement to the market price in accordance with a fixed, technology-specific strike price.
The strike price for CfDs is stipulated in annual auctions, where the awarded contracts have a duration of 15 years. To restrict expenses, the framework for the auctions is not volume-based, but indicates the total estimated cost for the State. A ceiling has also been set for the auction price. The first ordinary award round for CfD support contracts was initiated in the autumn of 2014. The first auction was held in the first quarter of 2015. No further auctions were held in 2015, but the authorities have announced that the next auction will take place in the last quarter of 2016. In 2014, the EU decided that the award of CfDs to the Hinkley Point nuclear power plant C (£ 92.50 /MWh) did not constitute a breach of the state-aid rules. The auction price for onshore wind (approx. £ 80) ended up lower than Hinkley, while offshore wind ended higher (£ 110 – 120).
The UK currently also has a floor for the carbon price, which sets a minimum price for CO2 emissions. This results in a substantially higher marginal cost for gas and coal power generation, and thus also higher prices in the wholesale market. While political support for a minimum price on carbon emissions may seem strong, there is uncertainty as to whether the United Kingdom will continue the practice if ETS is terminated, or remains at the current low level.
A capacity market has been introduced in the UK to ensure sufficient capacity during peak hours. The scheme is focussed on ensuring continued operation in existing power plants, securing necessary upgrades of existing power plants and, if applicable, also ensuring necessary new investments. The scheme also includes provisions for cut-off agreements with major consumers if that is most profitable. So far, two annual auctions have been held for the winters of 2018/19 and 2019/20, respectively and the prices have remained relatively low (£ 19.4 and 18.0 /kW).
The French market is mainly supplied by nuclear power and hydropower. In the summer of 2015, France set a nuclear power cap of 63.2 GW. This means that when the new plant, Flamanville, comes on line, an older plant, Fessenheim, must be taken out of operation. Furthermore, the French authorities resolved that nuclear power shall only account for 50% of consumption in 2025, compared with 75% as of today. Precisely what the latter resolution will entail in practice is not yet clear.
France is also increasing its renewable energy capacity (goal: 32% in 2030), although at a slower pace and with less ambitious goals than its neighbour, Germany. Greenhouse gas emissions are to be reduced by 40% in 2030, compared with 1990. The lack of flexibility from nuclear power plants and lower flexibility in neighbouring countries, together with substantial use of electric heating, has also led France to introduce a capacity remuneration mechanism (CRM) to maintain security of supply on particularly cold winter days. In contrast to the British system, the French have chosen a decentralised model, based on power suppliers covering their own power deliveries with the necessary capacity certificates. These capacity certificates are issued and controlled by the government, but are freely sold in the market between producers, suppliers and end customers (output reduction). The system will be functional for the first time in the winter of 2016/2017.
Albania's power consumption amounts to 7-8 TWh/year. This is a minor market due to its small population and modest economy. The Albanian market is headed towards deregulation, but it will obviously take time before a well-functioning market is in place for all players in the value chain.
Regional market liberalisation is under way, along with integration with nearby markets. This is a slow process, but Albania must still be viewed in context with its neighbouring countries for the purposes of assessing the power market in the country. Starting from a low point, the Balkans have experienced some economic growth in recent years. Despite a setback following the financial crisis, increased demand is expected in an intermediate perspective. In combination with phasing out a number of old, dilapidated coal power plants, this could set the stage for positive market development over time. Liberalisation of the regional power market in the Balkans is gradually expected to lead to wholesale prices that reflect the production costs in the region. We are already seeing wholesale prices in and around Albania that are converging towards an average in surrounding spot markets in Greece, Italy, Slovenia, Romania and Hungary.
Emerging markets are defined as markets where society and the business community are regarded as being in a phase of rapid development and growth. Turkey and all countries outside Europe where Statkraft is active fall under this category. The development here has also stagnated somewhat in recent years as consequence of the development in the rest of the world. Reduced growth in China and low commodity prices (i.e. large parts of the income in emerging markets) are important factors. Several of the countries also face political challenges.
The most important underlying drivers for emerging markets are population growth, urbanisation and economic growth, which in turn drive energy demand. In the time ahead, Statkraft expects demand growth in these markets, along with a significant increase in the development of renewable energy in the decades to come (see graph). It should be emphasised that many emerging markets have very different fundamental preconditions when it comes to economic maturity, the effectiveness of government institutions and organisation of the power market.
The most important uncertainty elements in these markets are:
- Fossil fuel prices;
- When the respective countries achieve a situation where the power markets are open, competitive and well functioning, with balanced supply and demand; and
- How the emergence of renewable decentral technologies will affect demand growth for centralised production. Solar energy with storage options (batteries) is particularly relevant as most of these countries have strong solar radiation.
In some markets, distributed solar energy could mean considerable change and have a substantial impact on demand growth for centralised power production. Since the infrastructure does not always keep pace with demand growth, distributed solutions can contribute to increased, and in some cases more reliable, power supply. While these countries are quite diverse in terms of structure, character and degree of development, all of them need new power production to meet rising demand. Since public investments in power production are unlikely to be sufficient to satisfy demand growth, commercial investors must recognise the opportunity for a reasonable, risk-adjusted return on their investments. Therefore, the prices in these markets must, over time, achieve a level that covers all operating costs, as well as the costs of capital for new power plants.
The Turkish power market is around 250 TWh/year. It has undergone liberalisation over the past decade, as production, transmission and deliveries to end-users have been organised in separate entities. In August 2006, the publicly owned central grid operator established a balance and settlement market, which was upgraded to a spot market in December 2011. Following facilitation through the new Power Market Act of 2013, an independent energy exchange was established in 2015. This is expected to contribute to higher liquidity, increased transparency and less opportunity for market manipulation. The Turkish central grid is connected and synchronised with the European market.
At present, Turkey has not committed to CO2 emission targets. Future CO2 regulation is uncertain, both in terms of level and type, and depends on uncertain volumes in e.g. international climate negotiations, relationship to the EU, and the issue of whether Turkey would prefer market-based solutions or more direct regulation. If a CO2 market is chosen, it is unlikely that this can be introduced before 2020.
Demand growth in Turkey has historically been strong, driven e.g. by population growth and economic development. Strong historical growth and a high percentage of gas power have kept prices high, and a large number of power plants were built and came on line in recent years. Significant new capacity, combined with somewhat lower demand growth over the last three years have contributed to a looser market balance, compared with previous years. The past year has also been characterised by an intensified conflict level within Turkey, and the region in general. This could have considerable implications in the form of e.g. declining investments in new production capacity if international players pull out; lower consumption growth if the general economy stagnates; and postponement or halts in the liberalisation processes as a consequence of shifting priorities and political instability.
Future development is still expected to be characterised by high consumption growth, compared with Europe in general, and somewhat lower development of new conventional capacity. In addition, the falling costs of photovoltaic cells and wind parks, the development in fuel prices, and whether or not Turkey adopts a price regime for CO2 will determine the price development. Turkey is well suited for distributed solar power, with ample sun and a demand profile that fits with the production pattern. Increased decentral solar power generation is expected to reinforce security of supply, as this will make it possible to avoid bottlenecks in local electricity grids. However, gas price levels and the pace of liberalisation in the gas market will be the most important factors for power price development in the intermediate perspective.
India is a huge market (~1000 TWh/year) with a high growth rate and the potential for development of hydropower. However, the risk in such a diverse and complex market is considerable, with regulatory complications, market imperfections and risk associated with doing business and licensing. Continued economic growth is expected, along with reforms and market liberalisation, a development that will make investments more attractive.
Demand for power in India has grown rapidly over the past decade. Higher household incomes combined with industrialisation and electrification of rural areas are expected to sustain the growth rates in the years to come. India is led by the reform politician Narendra Modi, who has launched a number of initiatives to secure necessary and important reforms.
There has been major capacity growth in the Indian electricity market in recent years, dominated by power plants fired by cheap Indian coal. However, the investment rate in new capacity is expected to decline, and the current overcapacity can be regarded as cyclical. Price regions have been established inside India, with moderate prices in the north and high prices in the south.
The Indian authorities have high ambitions for development of renewable power generation, a total of 175 GW by 2022. The country is particularly well suited for solar energy, both in central facilities and distributed to end-users. There has been uncertainty for quite some time as to whether these ambitious goals can be achieved, but the development in the past year has been positive, and the likelihood of renewable success has been reinforced.
The liberalisation process in the Indian power market is expected to continue. Gas and coal prices in India were regulated at a low level in 2014, but are expected to rise slowly toward a level that better reflects the alternative import price. Steps have been taken in this direction in the past year, and it is reasonable to expect that development will continue over the longer term.
The Indian distribution sector has been subject to economic pressure for quite some time, with low, regulated end-user tariffs, and high losses. In the current market, end-users' economic situation affects their ability and willingness to pay for power, which in turn keeps the wholesale prices low. Continued economic growth and reforms within the distribution sector are expected to improve willingness to pay, and thus have a net positive effect on future prices. There are already clear signs of improvement in the financial situation in recent years.
Brazil has a large domestic market, with total demand of more than 550 TWh. The recent years of low commodity prices have entailed just moderate growth and 2015 has been characterised by economic crises and recession. Despite lower demand in 2015 than in 2014, it is reasonable to expect underlying long-term growth.
The Brazilian power market is regulated, with considerable emphasis on security of supply. The economic crisis has necessitated increased private involvement in the transmission and gas markets. While this could be interpreted as a trend towards greater liberalisation over the longer term, the system will still be characterised by regulatory and political risk.
The power system is divided into a free market and a regulated market. Investments in new capacity are almost exclusively a result of auctions in the regulated market. Today, the system is dominated by hydropower, and is vulnerable to variations in water inflow. 2012 to 2014 were years characterised by drought and low inflow, which led to fear of rationing and blackouts in 2015. End-users experienced higher prices and expensive thermal power plants ran base loads to safeguard supply security. The hydrological situation has improved in 2015. While much of the thermal capacity has gradually been halted, reservoir levels are still not fully restored after the drought.
The price development in auctions for new, long-term power purchase agreements has revealed strong competition in the market, and price levels have been surprisingly low. This year's economic crisis has led to a rapid drop in the Brazilian Real, which has entailed that auction prices have increased in local currency. Wind power is still the most competitive technology in Brazil, due to favourable wind conditions.
Wholesale electricity prices in Chile have been among the highest in Latin America. Continued demand growth is expected in the years to come, but the decline in commodity prices has a negative effect on Chile's mining sector, and thus a negative impact on power consumption in the industrial sector.
Chile has a liberal and stable regulation framework that stimulates private investments for both new and old players. The market is characterised by a large influx of private capital, where new capacity is added to the market after market-based investment decisions, as well as central, organised auctions. At the moment, the trend is towards entering into long-term contracts through auctions and market-based contracts with industry. This reflects the players' belief that spot prices will fall as a result of lower fuel prices, lower growth in demand and a wave of solar and wind capacity expected in the time ahead.
Over the course of recent years, the growing awareness of environmental impact and profiling of social and civil rights have led to grass roots opposition and protests against power projects, which has made it more challenging to build both coal and major hydropower plants, as well as the transmission grid. A recent Government initiative, Energis 2050, is aimed at creating greater acceptance for progress in energy projects.
The conditions for solar energy are considered to be particularly favourable, especially in the north. Wind has also exhibited strong growth. Later auctions have been adapted to the variable and intermittent profile of solar and wind through a more sensitive time perspective.
Given Chile's long and narrow geography, transmission capacity will be a recurring challenge, although promising projects are under way to reinforce the grid and link the northern and central systems. Transmission restrictions and differences between price areas may be a challenge, but also represent a future opportunity for market players.
Peru has a relatively stable and robust growing economy. However, the end of the commodity boom will have a negative impact on demand in the short to medium term, based on the mining industry.
Until 2000, the Peruvian power system was dominated by hydropower, with only modest use of natural gas and fuel oil in power generation. The discovery and development of significant gas resources and low, politically-determined gas prices have spurred the development of gas power, accounting for more than half of installed capacity today.
Low spot prices make capital-intensive investments in new power capacity in Peru dependent on subsidised long-term power sales agreements with special incentives for new power generation. The power purchase agreements for Statkraft's Cheves hydropower project are a result of such a tender process. The current surplus of both power and new projects curbs development of new projects over the medium term.