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 economic growth, and emerging markets with more vigorous growth. However, economic 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:

  • Climate policies and climate change. As many as 195 countries gathered in Paris December 2015 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. By November 2016 this agreement went into force as at least 55 countries representing at least 55% of the global emissions had signed. 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. At the same time electrification is the key to decarbonise the economy, especially in transport and heating/cooling sectors. In November 2016, the World Meteorological Organization (WMO) reported that 2016 will probably be the hottest on record. On the positive side WMO reports that emissions have stabilised for the third year in a row.
  • 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. Lately PPAs and auctions are gaining force and both solar - and wind power is competitive in a number of  markets around the world, even without subsidies.
  • Centralised power system will prevail, despite distributed trends. Declining costs for small-scale power production and storage 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 being used more frequently also for balancing services. Still we see that  also centralised systems will be needed to balance systems.
  • Uncertain fuel prices. Global fuel prices (oil, gas and coal) dropped significantly during 2014 and 2015. Prices below 30$/bbl was seen in Q1 2016 but has been ~50 $/bbl by the end of the year. Coal prices have seen substantial increase during H2 in 2016 due to reduced Chinese production. These developments along with climate policy and development of technologies for replacing fossil fuels have led to a more pronounced general perception of uncertainty about future fuel prices and hence the power prices.

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 2016. Starting from last year, expected primary energy consumption in 2040 has been reduced by 0.6%.

World primary energy demand

(click on image to enlarge)

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 (-5%) of primary energy demand in 2040 than in 2014. This is slightly lower than last year’s projections (-4%).

Share of growth

(click on image to enlarge)


The power markets in Europe are impacted by two strong trends: The first is stagnating demand, partly due  to repercussions after the financial crisis,  phase-out of industry, transition to more service activities and in part due to energy efficiency measures. Forecasts indicate that demand will not rebound to 2007/2008 levels until 2020. The second trend 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 triggered considerable new renewable capacity in markets where demand has stagnated, and thus less need for generation 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. Still the power prices will be highly influenced by gas and CO2 prices.

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 connection to this, the EU introduced a Market Stability Reserve (MSR) in 2015. The scheme will take effect in 2019. Both of these decisions are expected to increase the price of emission quotas somewhat in the time ahead. In December the European Parliament’s Environment Committee voted for a revision of the EU ETS. The vote includes a number of important measures aimed at strengthening the ETS which includes doubling the intake rate of the Market Stability Reserve, MSR, an increase in the linear Reduction Factor and cancelling 800 million allowances from the MSR in 2021. The revision will later go through Parliament and Council and can be changed before it is final. On the other hand, Brexit and heavy lobbying from industry and Eastern European Member States add to the uncertainty of a real strengthening of the ETS in the future.

The Commission presented its "Summer Package" in 2015, aiming at creating a truly integrated energy market. Following the publication of the Summer Package, the Commission presented the “Winter Package” in November 2016  as the next important step towards the implementation of the Energy Union. The Winter Package comprises a large set of proposals from Commission to implement the Energy Union, including both legislative as well as non-legislative initiatives. The Winter package, now called ”Clean Energy for all Europeans”, covers measures of energy efficiency and energy performance of buildings, renewable energy, the design of the electricity market, security of electric supply and governance rules for the Energy Union.

Of other elements we see increased cross-border participation in capacity markets and a proposal to restrict the use of national capacity markets. Further it is proposed to remove  dispatch priority of renewables. On the other hand the objective to complete the Internal Energy Market (IEM) is removed and replaced by the “consumer at the centre of the energy system”, i.e. tariffs, distributed energy, demand side management a.o. Energy efficiency goal for 2030 is binding on an EU level and increased from 27% to 30%. Energy performance requirements of buildings are strengthened. It is proposed to introduce common principles for the design of support schemes to further develop RES. The package is now out for a two year process in Parliament and Council.

Nordic countries; focus on Norway and Sweden

A joint green energy certificate scheme (Elcert) was launched in 2012. This is a market-based subsidy scheme aimed at promoting renewable energy generation in Norway and Sweden. Using this scheme, Norway and Sweden have a shared objective of achieving 26.4 TWh of annual new renewable generation by 2020. In  2016, Sweden added 2 TWh to their quota. Further Sweden have added 18 TWh to their quota and extended the period to 2030. The investment deadline for Norwegian projects under the Elcert scheme is end 2020. There is a discussion going on between energy authorities in Norway and Sweden on how to align the extensions with the current system. The Norwegian-Swedish Elcert market, combined with Finnish and Danish subsidy schemes for new renewable energy sources and a new nuclear reactor coming online in Finland, will lead to a significant energy surplus in the Nordic electricity market. 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 power production prices are highly dependent on the price development in surrounding markets, and the number of new  interconnectors being built. Concrete plans are in place to double the exchange capacity out of the Nordics until 2025.


The German electricity market is greatly impacted by “Energiewende”, a political term describing the process away from nuclear power and the way to 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 solar (PV) up to 2012. By end 2015 totally ~40 GW of solar PV was installed. Total installed wind capacity in Germany by end 2015 was ~48 GW, of which 3.3 GW were offshore. Additions during 2016 are assumed to be 4 – 4.5 GW, while for solar it is estimated ~2.5 GW.

The combination of growth in renewable capacity and flat energy demand has resulted in a significantly lowered need for conventional thermal power production. With the influx of intermittent renewable sources come changes in profiles for both prices and the call for thermal capacity (residual demand). Solar power production is highest in the middle of the day, thus inverting the previous mid-day peak to becoming price slump. As a consequence, conventional thermal power plants in Germany have experienced dramatic changes to their operating conditions. On the 15th of May 2016 at 2 p.m. as an example, wind and solar generated 45.5 GW while the total demand was 45.8 GW. Renewable covered almost all demand. Conventional power plants still generated 7.7 GW so Germany was exporting to neighbouring countries.

Today, much of the German flexible power production from gas and coal struggles to cover its current capital expenditures and even parts of their fixed operating costs. In principle, this should mean that these power plants should either be mothballed or shut down permanently. However, as solar- and wind power yield uneven production and there are limited solutions to the storage capacity issue, this could have reduced supply security to an unacceptable level. For this reason, the German authorities have introduced a law banning system-critical power plants from being shutdown, causing  significant uncertainty surrounding the closing of thermal power plants.

The German government adopted extensive power market reforms in November 2015 that came into force in summer 2016. The reformed "Power Market 2.0" entails that no capacity remuneration mechanism will be introduced. This implies that security of supply 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. 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-fired power plants that are to be phased out of the market and shut down. These reserves cannot take part in the market.  The strategic reserve mechanism will be extended to after 2017, when the grid reinforcement projects have been completed.

United Kingdom

Electricity Market Reform (EMR) is a government policy to increase investments in secure, low-carbon electricity, improve the security of electricity supply and improve affordability for consumers. 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. In accordance with EMR the British authorities have supported the 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 (5.1 GW by end 2016) than the rest of the world combined. In May 2016 UK experienced hours where coal power generation was zero and in one week renewables generated more energy than coal plants.

The authorities want to develop new nuclear power plants, NPPs, to replace power plants nearing the end of their technical lifetime.  In June EdF made its decision to proceed with the new nuclear power plant Hinkley Point C. China General Nuclear Power Corporation  will provide 1/3 of the costs totalling £18bn. In September the UK Government took the final decision to move forward with the project. Construction start is expected mid-2019 and commissioning is expected 2026.

In 2010, the UK launched a certificate and quota system, the Renewables Obligation Certificates, ROC. Between 2014 and 2017, as part of the British electricity market reform, ROCs will be replaced by a system of  Contracts for Difference (CfDs). The  strike price for CfDs is stipulated in annual auctions. The first auction was held in the first quarter of 2015. The UK Government announced in November 2016 that the application process for the next CfD Auction will open in April 2017. In 2014, the EU decided that the award of CfDs to the Hinkley Point NPP 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), but for a 15 year contract versus 35 for Hinkley Point C.

A capacity market has been introduced in the UK to ensure sufficient capacity during peak hours. The scheme is focused 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 cost-efficient . Previously, two annual auctions have been held for the winters of 2018/19 and 2019/20 respectively, and the prices have remained relatively low at GBP 19.4 and 18.0 /kW. In December an auction for winter 2016/2017 cleared at 22.5 GBP. A new auction will be held late 2017 for the winter 2018-19.

In June 2016 the UK voted to end its membership in the EU (Brexit). The vote is expected to have negative effect on growth, hence also on energy demand for the next couple of years.

The UK currently also has a national tax on carbon emissions, carbon price floor, of GBP 18/ton in addition to the EU ETS. 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 the ETS price remains at the current low level.


France has introduced a law on energy transition and green growth called “Loi sur La Transition Énergétique et la Croissance Verte”, (LTECV). In accordance to this France has set a nuclear power cap of 63.2 GW. This means that when the new plant, Flamanville, comes online, 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 to 75%  today. EdF is given responsibility to define a strategy for implementation of this. During the autumn of 2016 France experienced high wholesale prices due to a high numbers of outages of nuclear plants. While building Flamanville 3 it was discovered weaknesses in steam generators due to steel quality. This problem also affects some of the existing generators, hence some had to be taken out of operation temporarily for inspection and maintenance, causing temporarily high prices. The nuclear plants are assumed to be online again in 2017.

France is also increasing its renewable energy capacity. Further a Contract for Difference for renewables was introduced in 2016. The low flexibility from nuclear power plants, 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 UK 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 (demand reduction). The system will be functional for the first time in the winter of 2016/2017. The clearing price in December auction was 10 €/kW.


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 level, the Balkans have experienced some economic growth in recent years. Despite a setback following the financial crisis, increased demand is expected in a mid-term perspective. In combination with phasing out a number of old 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.

Emerging markets

Emerging markets are defined as markets where society and the business community are regarded as being in a phase of rapid development and growth. The development here has also stagnated somewhat in recent years as a 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.  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 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). In IEA’s WEO 2016 there is a remarkable increase in forecasted RES 2040 from last year totalling 100 GW in OECD, 370 GW in non-OECD and 350 GW in China (sum solar and wind), partly due to the initial growth 2013 to 2014. The climate policies in these countries are more a result of local resources, covering increasing demand and that there might be other more cost-effective ways of limiting emissions than within the power sector.

Growth in installed

Several of the EM-countries are practising some kind of auctioning or Power Purchase Agreements, PPA, to attract investors. This will mostly be utility scale/centralised projects. In some markets, distributed solar energy could mean change and have an 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.


The Turkish power market is around 250 TWh/year. 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 2025.

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 addition of 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 in and around Turkey, culminating in an attempted military coup followed by a state of emergency. This could have considerable implications in the form of e.g. 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. Declining investments in new production capacity and Turkey as such could also be a consequence if international players pull out.

Future development is still expected to be characterised by relatively high consumption growth, compared with Europe in general. 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. We are also expecting some new wind farms based on auctioning connections to the grid and feed in tariffs. However, gas price levels, CO2 regime and the pace of liberalisation in the gas market will be the most important factors for power price development in the mid-term perspective. Further application has been made for construction and operating licences for the first nuclear power plant (4.8 GW Russian) at Akkuyu. Construction start is expected in 2018 and commissioning is expected in 2023 and onwards.


India is a huge market (~1100 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. Prime minister Narendra Modi has launched a number of initiatives to secure necessary and important reforms.

Power demand  in India has grown rapidly over the past decade. Increased household incomes combined with industrialisation and electrification of rural areas are expected to sustain the growth rates in the years to come.

There has been major capacity growth in the Indian electricity market in recent years, dominated by power plants fuelled by cheap Indian coal. However, the investment rate in new capacity is expected to decline, and the current overcapacity can be regarded as cyclic.

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 previously, but are expected to rise slowly toward a level that better reflects the alternative import price. The coal industry undergoes an improvement programme with strong support and encouragement from the authorities, securing sufficient volumes to the power plants. It is a stated goal that all import should be abandoned where technically feasible. In such a situation there may even be a local coal price formation in areas more or less independent of the global market price, creating a downward pressure on the power price.

The Indian distribution sector has been subject to economic pressure for quite some time, with low, regulated end-user tariffs, and high losses, including theft. A new scheme (UDAY) is introduced which reinforce the distribution sectors economy, combined with reforms towards cost reflective pricing. 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 575 TWh. We see a flat development from 2015 to 2016. The recent years of low commodity prices, poor credit rating and political crises have led to recession and shrinking power consumption.  Despite this short term trend, 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 a trend towards greater liberalisation over the longer term, the system will continue to 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. The hydrological situation has improved dramatically in 2016.  While security of supply was the main concern for energy planners last year, dealing with oversupply, and oversupplied distributors, has now taken its place. Significant new capacity , 9 GW has come online this year,  mainly wind (2.9 GW) and hydro (5.4 GW). Meanwhile, auctions have slowed down as demand for energy has not materialized amidst the oversupply.


The electricity demand in Chile reached 66.7 TWh in 2016 compared with 66.5 TWh in 2015. Wholesale electricity prices in Chile have historically been among the highest in Latin America, but have seen a significant decrease since last year. Continued demand growth is expected in the long term, 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 mining and industrial sector.

Chile has a liberal and stable regulatory framework that stimulates private investments for both new and old players. The market is characterised by a large influx of private capital. New capacity has historically been merchant based. The current trend is towards entering long-term contracts through regulated auctions and PPAs with industry. This reflects the players' belief that spot prices will remain low as a result of lower fuel prices, lower growth in demand and a wave of solar and wind capacity expected in the time ahead.

The growing awareness of environmental impact and profiling of social and civil rights have led to grass roots opposition and protests against power projects, making it more challenging to build coal and large hydropower plants, as well as transmission grids. A recent Government initiative, Energias 2050, is aimed at creating greater acceptance for progress in energy projects.

The conditions for solar energy are considered to be particularly favourable; however wind has shown strong growth in recent auctions. Auctions rules have been adapted to the variable and intermittent profile of solar and wind by tying contracts to day of time blocks.  Winning bids have decreased in price dramatically in the past year as renewables have outcompeted conventional power. The trend has led to concerns about whether thermal power can compete in the future and how security of supply can be guaranteed. 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. A new transmission law was passed this year that should make transmission planning more forward thinking, and allocate the cost of transmission to the energy users. That law should encourage development of Chile’s vast renewable energy resources found far from load centres. Transmission restrictions and differences between price areas may be a challenge, but also represent a future opportunity for market players.


Electricity demand in Peru was 44.5 TWh  in 2015 and 48.3 TWh in 2016. Peru has a relatively stable and robust growing economy. However, the end of the commodity boom has a negative impact on power demand in the short to medium term, primarily due to 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 plant 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.