Summary Report UK s Long Term Power Balance and Implications for Major Power Producers Gas Consumption

Transcription

1 Updated 17th of June 015 Summary Report UK s Long Term Power Balance and Implications for Major Power Producers Gas Consumption Ambitious cuts in greenhouse gases and strong promotion of renewable energy are central points in UK s energy policy towards 00. These targets will ensure strong promotion of renewable electricity. Towards 00 we expect dependency on gas power to be dominant in UK s power balance. Looking a few years beyond, we expect increases in nuclear power, further promotion of renewable electricity, increased net exchange capacity and energy efficiency driven reductions in power demand to reduce dependency on gas for gas power generation. Largest uncertainties with the British power balance: Development in the political controversial Hinkley Point C and other nuclear projects in the pipeline Hourly distributions of renewable power technologies Power consumption development Copyright 015 Markedskraft ASA. Please note that this report is subject to specific restrictions on distributions. The terms and conditions are available on

2 Summary Introductory remarks and major assumptions Our analysis of UK s power balance development towards 00 is to a large extent dominated by long term energy projections conducted by Department of Energy and Climate Change (DECC), as published in September 01. For our prognoses of power balances in the long term, we have studied a historically hour-by-hour development of all parts of UK s power balance, accompanied by hourly price development. Long term energy policy has been the basis for expectations to how the hourly power balance will develop. Among the most central assumptions behind this study is UK complying with its long term targets for greenhouse gas reduction and increased renewable energy. Also respecting security of supply is taken into account. Commissioning of the controversial nuclear power station Hinkley Point C is taken into account in our assumptions. Assessment of various power balance elements towards 00 The UK power system has for many years been dominated by nuclear power and thermal power generation, while renewable electricity levels have been rather modest until recent years. In 01, UK s net public thermal power supply generated 19 TWh, 58 TWh of nuclear power and some 6 TWh of renewable power. Net imports totaled 1 TWh. The thermal power system in UK is mainly based on hard coal and gas, and is known for having the highest flexibility of switching between these fuels in Europe. UK has a strong focus on reducing its dependency on thermal power generation. It targets in particular hard coal power generation, and due to this we find it likely that significant reductions in hard coal power in the long term will occur. UK has traditionally been considered a very climate friendly country, having strong ghg abatement ambitions. The current targets for ghg emissions are strong decreases in five year average emissions, a 50% ghg cut in 07 compared to 1990 levels and a 050 target of 80% ghg emissions cut. Looking to the and 0-07 periods, we expect decreases in households and transportation to constitute large emission reductions, while instruments targeting a gradual phase-out of hard coal will ensure abatements in the power and heat sector. According to projections made in September 01 by DECC, and the recently submitted National Energy Efficiency Action Plan (NEEAP), British energy authorities project a decrease in total thermal electricity generation in the 80 to 90 TWh range from 01 till 00, of which much will be coal fired generation. UK has been levied a renewable energy target for 00 of 15%. In 01, the renewable energy share was %. A massive expansion in green electricity, along with a decrease in final energy consumption, is part of UK s strategy for reaching the target. In UK s National Renewable Energy Action Plan of 010, it was projected a green electricity generation in 00 of 117 TWh Total renewable electricity for UK in 01 came out at 6 TWh, comprising 1 TWh of wind power, TWh of photovoltaic power, 6 TWh of hydropower and TWh of bioelectricity. The 01 output is exceeding the trajectory established in the 010 NREAP. During the last couple of years a tremendous increase in wind power capacity has come online, of which offshore wind power has risen substantially lately. The increased capacity seems to coincide well with 010 projections so far. Applying preliminary figures for four months this year, and with assuming continued growth in capacity, we expect total wind power to reach 7 TWh in 015. The major reasons for overperforming renewables are bioelectricity and photovoltaic power. The latter has increased strongly the last couple of months, and according to DECC, some 5.7 GW of capacity was installed by end of March 015. Looking at the total renewable electricity generation projection for 00 of 117 TWh, we conclude that some 5 TWh/year of increased renewable electricity compared to 01 will have to be commissioned. We assume the 5 TWh/year increase to be balanced this way: 8 TWh/year from photovoltaics, 5 TWh/year from offshore wind, 15 TWh/year from onshore wind, nearly 0 TWh/year from tidal and hydropower and TWh/year from bioelectricity. After the financial crisis, power consumption has not increased back to 008 levels. While 008 consumption was some 8 TWh, we expect 015 consumption to drop to TWh. According to how we perceive prognoses from DECC, power consumption in 00 will be close to 01 level, which was extra low due to mild temperatures. We perceive energy efficiency efforts to be a major contributor to the decrease, particularly in household appliances. Increased interconnectivity between European member states will play a role in the security of the system, facilitating competition and supporting the efficient integration of renewable generation. We have taken into account that current net import capacity will be reinforced with some 6.8 GW by 0. UK has 16 nuclear reactors, and the net nuclear generation in 01 amounted to 57.9 TWh. Over the period, nuclear power capacity is set to increase. According to British authorities, increases in nuclear power generation should be motivated by the transition to a low carbon future and still providing reliable power supply. Looking at nuclear capacity towards 05, we acknowledge that British authorities have assumed more than a doubling of nuclear capacity/nuclear power generation. Given the strong controversy with nuclear power in general, and the observed controversy associated with Hinkley Point C, we assume that UK s nuclear capacity will increase from the current 10 GW to some 1-1 GW, and then maintain that level towards 05. The 1-1 GW level includes Hinkley Point C and several others of the nuclear projects in the pipeline, in a pace that compensates for decommissioning of the existing nuclear plants. We do not expect much of an increase in British CHP capacity. Current CHP capacity is some 6 GW, of which almost everything is gas. From 018 UK will have a capacity mechanism running. This mechanism will both be supply and demand side measures to ensure security of supply. Copyright 015 Markedskraft ASA

3 Power balance development historically and towards 05 on hour-by-hour basis Today the UK system is very much based on fossil power generation. Nearly all hours are to be solved with price dependent power generation, for both summer and winter. Forward prices strongly reflect the dependency on hard coal and gas. Gas power is the balancing technology for UK s power system. Towards 00, three new interconnectors have entered UK s power system, while we expect by then to have nearly a doubling of today s photovoltaic capacity, while we expect the projected 00 onshore and offshore capacities of 1 GW and 15 GW to have been reached. Also, temperature adjusted power demand will be lower than the last couple of years level. For 00, we expect power prices will be cleared at continental price levels or lower at least for 1% of the hours. Towards 05, additionally three new interconnectors will enter the system. We expect further increases in renewable electricity, and by 05, the Hinkley Point C nuclear reactors will run at full operations. Hence, by 05 the increase in capacity from nuclear power, renewables and interconnectors will ensure that thermal power generation is only necessary to cover demand for nearly half of the hours over the year. For 00 and beyond, we expect pretty much the same development, as increased renewables counteracts increased power demand. Gas consumption from major power producers The UK relies to a large extent on natural gas as a main source for energy. A significant share of the gas consumption is used for power generation, with variation band -5% during latest 1 years. In the UK gas-fired power generation took -5% of the total gas consumption in UK. During the years 01-1 and probably also for the years the share fell to -5%, as price relations came out less competitive for gas in power generation plants. Gas-fired generation has during latest years stayed at top of the merit-order curve, which is likely to persist in the long term. Then it is automatically the swing-producer, and is exposed to nearly all changes in the power balance. This is the case both in UK and also in some European countries. With the renewable goals set to increase and the consumption to be steady or fall slightly, the share of gas-fired generation is on falling trend both in UK and Europe. One major difference between UK and rest of Europe when it comes to merit-order curves and SRMCs (Short Run Marginal Costs), is the UK-imposed CO carbon tax. Due to the UK-imposed CO-price, the coal- and gas-fired generation is more expensive in UK than in the other European countries. When existing and planned interconnectors are taken into account, the imports to UK will often turn out at maximum physical capacity. Gas-fired generation costs (SRMC gas-fired) are still giving the spot price signals for nearly all hours in UK, while in Continental Europe the amount of hours when SRMC gas-fired generation giving spot price signals is coming closer and closer to zero year by year. The less expensive coal-fired generation from Continental Europe will gradually reflect spot prices in more and more of the hours throughout the year in UK, in a situation where UK s own coal-fired generation capacity is the middle of a decommissioning process. In our main price scenarioes base, low and high, the price gap between SRCM coal- and gas-fired generation are expected to sustain. But we also have made calculations for how deep the gas-price must fall to equalize SRMC gas-fired and SRMC coalfired generation in our three main scenarios. We assume the price of coal deliveries to ARA in the base scenario to be close to 60 $/t during , in real terms. The price expectations are approx. in line with the forward market prices (as of mid May 015) until 018, and thereafter we assume a constant level. In the base scenario, we assume that natural gas prices referred to Dutch TTF in real terms will start at around 1 /MWh in 016-0, and then level out close to 0 /MWh for the period The price expectations are in line with the forward market prices (as of mid May 015) until 01. Looking at , we assume market prices for EUAs as far as they go, for then increasing gradually to 1 /t in 05. To equalize SRMC gas-fired and coal-fired generation in UK in 00, gas-prices need to fall quite dramatically to make the two fossile-fuelled generation methods equal. In the base scenario, a gas price fall of 7%, from 0. to 1.7 /MWh for Calenderyear products (in TTF-terms) is needed. In rest of Europe a gas price fall of 5%, from 0. to 9.7 /MWh is needed to equalize SRMC gas-fired and coal-fired generation. In case of gas price fall of 5%, the consumption of gas in power generation will increase dramatically. This will reduce coal-fired Non-thermal power hours for UK Winter workingdays Winter weekends Summer workingdays Summer weekends Annual total hours Copyright 015 Markedskraft ASA

4 generation in Europe correspondingly. Our conclusion from this study, is that we will see significant change in UK s gas-fired generation. During the period we observed high consumption of gas in UK gas-fired power plants, in average 1 TWh/year or 5 Mtoe. During the period 01-0 we expect to see a 7% lower level, in average 76 TWh/y power generation and 1 Mtoe of fuel consumption. For the period 05-00, we expect even lower gas-fired generation, in average 5 TWh/y and 9 Mtoe of fuel consumption. The main drivers for the development is increased renewable generation, high imports of power via interconnectors and slightly lower consumption level. Also plans for development of new nuclear generation capacity give signals for reduced gas-fired generation. The development of generation from gas-fired plants in UK during the historical period 005 to 01 and our expectation for the development until 00 is shown in table. Gas power generation and gas consumed for power generation Year Gas power generation [TWh] Gas consumption for power generation [Mtoe] We also foresee a development of changes in how gas-fired generation is operated in the UK power market. Until approx. 00, gas-fired generation is the swing-generator which give the price signals nearly all hours during a year. Volumes of gas-fired generation is of course always changing from hour to hour, as balancing the market is the key-role for gas-fired generation. From approx. 00 on, we expect that a change will affect the market: Gas-fired generation will balance the market in 86% of the hours throughout the year. For rest of the year, the new interconnectors will more and more balance the UK power market. Gas-fired power plants will see more and more startstop sequences and lower utilization periods. From approx. 05 on, we expect that the change is more significant: Gas-fired generation will balance the market in some 50% of the hours throughout the year. For the rest of the year, we expect that the new interconnectors will balance the UK power market, and we may also see high renewables output causing price collapses. Gas-fired power plants will face a larger amount of start-stop sequences and lower utilization periods. The plants will still be in a key-role for balancing the market, but with lower utilization periods and lower profitability. Net exchange on new link Norway-UK The new cable link Norway-UK is expected to be operational from January During the first two years of operation, we expect that 86% of the UK spot hours throughout the year are defined by expensive SRMC gas-fired generation. The UK spot prices are for rest 0% of the year expected to come out close to Central European SRMC coal in average. The net result will be nearly full export out of Norway (100 MW) during 86% of the hours. And for the remaining hours, we expect close to zero net exchange. The net effect will be approx. 10 TWh/y net exchange level during the first two years of operation. From 05 on and until 00, we expect that 50% of the UK spot hours throughout the year are defined by expensive SRMC gasfired generation. The UK spot prices are for rest 50% of the year expected to come out close to Central European SRMC coal in average. The net result will be approx. full export out of Norway (100 MW) during 50% of the hours. For the remaining hours, we expect close to zero net exchange. The net effect will be approx. 6 TWh/y net exchange level during this period. During the period 0-5 we expect net exports to drop Net annual exchange from Norway to UK [TWh/year] gradually from 10 to 6 TWh/y. See figure. We assume that the same net exchange patterns will be observed for nearly all interconnectors to UK, except for the Irish interconnector(s). A second cable link Norway-UK (NorthConnect) as we assume from 0 on, will double the export from Norway from 6 to 1 TWh/y. This corresponds to a reduction in UK s consumption of gas in gas-fired plants of Mtoe. The first cable link Norway-UK (NSN) will increase Nordic power system price by 1.5 /MWh and nearly /MWh for most of the Norwegian price areas (except for in NO) for the first two years Copyright 015 Markedskraft ASA

5 5 Net annual exchange from Norway to UK and corresponding effect on gas consumption in UK [TWh/year] Norway-UK 100 MW Norway-UK 800 MW Norway-UK 800 MW Norway-UK 100 MW [Mtoe/year],5 1,5 1 0,5 of operation (01-). The price effect will be lower from 0 on, 0.9 /MWh for Nordic system price and 1.1 /MWh for most Norwegian area prices, as net export level is expected to fall significantly. The figure shows the expected net exports of power from Norway to UK for one and two 100 MW cable links (from 01 and 0 on, respectively). The first cable link starts at 10 TWh/y flow to UK 01-, gradually falling to 6 TWh/y from 05 on. With two links expected to be available from 0 on, the flow will be 1 TWh/y from 05 onwards. The corresponding reduction in UK gas demand due to power exports from Norway will be in the 1 to Mtoe range. This corresponds to % to % of the total UK gas consumption per year. We expect that this impact will not be of major significance in the NBP gas market in any of the gas price scenarios. Still, seen from a gas market participant perspective, a minor gas price change may give significant influence on gas price multiplied with gas volume for market participants with large volumes in the gas market. However, if we assume a net power import via all existing (. GW) and expected additional cable links (6.8 GW) to UK of TWh/y, a reduction in demand for gas in UK of some 7 Mtoe can be expected. This corresponds to a reduction in UK gas demand of 1% per year, and this a more significant share of volume in the NBP gas market. Copyright 015 Markedskraft ASA