EU Energy Policy Continues To Leave Utilities In The Dark

BMI View: The operating environment within the EU energy market remains extremely challenging for utilities, as the region's energy policy and future trajectory of it remains confused as policy aspirations and economic realities vie for prominence. In the first part of this two-part analysis, we will examine the uncertain future of gas-coal price dynamics, the EU regulations governing coal-power plants and the potential power-capacity crunch in Europe as utilities stall on building new capacity in light of the confused policy environment. If these issues are not addressed through policy implementation, there is a real risk of jeopardising the region's future energy security and capacity expansion plans.

Shifting economic and policy dynamics within the European energy market have resulted in coal becoming the most competitive source to generate power - a trend that we have been following closely in our analysis (see 'Coal Comeback Continues', June 19). Coal prices remain relatively low following their collapse in 2011, and gas prices remain high - following the steep increase in wholesale gas prices in 2011. Furthermore, and exacerbating the growing divergence between the cost of coal and gas-fired power generation (dark-spark spread), has been the continued policy stalemate of the EU emissions trading scheme (ETS), which is providing no mechanism to discourage the burning of coal (see 'Successful Vote Throws ETS A Lifeline', July 5). Initially, we believed that it was unlikely that this dynamic would change until at least 2016, however, a continued failure on a policy level to create a sustainable long term policy environment and ongoing uncertainty over coal/gas price dynamics lead us to believe this will remain an issue through to the end of the decade.

Quite clearly, the renewed focus on coal as a fuel source for the power sector, which led to carbon emissions rising in both Germany and the UK in 2012 - reversing a long downward trend - comes as a stark contradiction to the global image of the EU as a 'green champion'. In fact, we believe we are witnessing a softening stance towards stringent environmental regulation in Europe, as the region's decreasing competitiveness and rising energy costs take centre stage - something will we be looking at in more detail in part two of this analysis. This viewpoint was encapsulated in the summer of 2013, when an EU official stated that energy talks should be undertaken 'through the lens of prices rather than climate concerns'.

Economic And Policy Case For Coal
Dark-Spark Margin EUR/MWh (LHS) and European Energy Exchange (EEX) Spot price (EUR/tCO2) EU Allowance Period 3 - Last Price (RHS)

BMI View: The operating environment within the EU energy market remains extremely challenging for utilities, as the region's energy policy and future trajectory of it remains confused as policy aspirations and economic realities vie for prominence. In the first part of this two-part analysis, we will examine the uncertain future of gas-coal price dynamics, the EU regulations governing coal-power plants and the potential power-capacity crunch in Europe as utilities stall on building new capacity in light of the confused policy environment. If these issues are not addressed through policy implementation, there is a real risk of jeopardising the region's future energy security and capacity expansion plans.

Shifting economic and policy dynamics within the European energy market have resulted in coal becoming the most competitive source to generate power - a trend that we have been following closely in our analysis (see 'Coal Comeback Continues', June 19). Coal prices remain relatively low following their collapse in 2011, and gas prices remain high - following the steep increase in wholesale gas prices in 2011. Furthermore, and exacerbating the growing divergence between the cost of coal and gas-fired power generation (dark-spark spread), has been the continued policy stalemate of the EU emissions trading scheme (ETS), which is providing no mechanism to discourage the burning of coal (see 'Successful Vote Throws ETS A Lifeline', July 5). Initially, we believed that it was unlikely that this dynamic would change until at least 2016, however, a continued failure on a policy level to create a sustainable long term policy environment and ongoing uncertainty over coal/gas price dynamics lead us to believe this will remain an issue through to the end of the decade.

Economic And Policy Case For Coal
Dark-Spark Margin EUR/MWh (LHS) and European Energy Exchange (EEX) Spot price (EUR/tCO2) EU Allowance Period 3 - Last Price (RHS)

Quite clearly, the renewed focus on coal as a fuel source for the power sector, which led to carbon emissions rising in both Germany and the UK in 2012 - reversing a long downward trend - comes as a stark contradiction to the global image of the EU as a 'green champion'. In fact, we believe we are witnessing a softening stance towards stringent environmental regulation in Europe, as the region's decreasing competitiveness and rising energy costs take centre stage - something will we be looking at in more detail in part two of this analysis. This viewpoint was encapsulated in the summer of 2013, when an EU official stated that energy talks should be undertaken 'through the lens of prices rather than climate concerns'.

EU Energy Market Chaos

As stated, we now believe that this disparity between policy aspirations and economic realities could rumble on through to the end of the decade. Consequently we expect the operating environment for the major stakeholders involved within the EU energy market, primarily utilities, to remain challenging, with the confusion surrounding the direction of the energy agenda likely to have a knock-on effect on capacity expansion plans and investor sentiment.

This is based on a number of factors - stemming primarily from the differing dynamics within the coal and gas sectors. Coal is undoubtedly the most preferred option for electricity generation in a number of countries at present, and will continue to be over the short-term. However, EU regulations governing large combustible plants should see a significant amount of coal-fired plants go offline, unless expensive technology is introduced to reduce emissions. In addition to this, gas at present is not a favourable option, given the high gas prices - and our longer term outlook sees prices remaining elevated. These factors, combined with the fact that nuclear continues to present a prohibitively high alternative for power generation, is leading us to question what power capacity will be built in Europe over the next decade.

Until the EU takes a bold step, in terms of policy, to address these issues - by reforming the ETS programme (industry sources believe that carbon allowances need to rise to around EUR40/tCO2 to shift economical preference to gas) or perhaps subsidising gas-fired power plants - the chaotic situation the EU energy market finds itself in is unlikely to resolve.

Coal In The Limelight...But Scheduled Offline

As mentioned, coal prices have collapsed since early 2011 and we foresee only a modest recovery going forward. One driving factor in the decrease of European coal prices has been the surge in export supply from the US and we certainly do not see a reduction of exports across the Atlantic, particularly given the current situation within the country's power sector.

The shale gas boom pushed natural gas prices down; driving utilities towards gas-fired power generation as it fast became the most competitive way to generate electricity. However, coal-fired generation fared less well and since President Obama was first appointed into office in 2009, a reported 15GW of coal-fired power facilities have closed - much to the detriment of US coal producers. Recent Environment Protection Agency (EPA) regulations governing carbon standards for new power plants have effectively cemented the new status quo of the US power mix that has been established over the last two years and we believe there is little upside for coal-fired generation in the US (see 'EPA Carbon Standards Cement Shift In Power Sector', September 27). As such, we expect to see seaborne coal to continue finding its way to European ports, which will help to offset the otherwise supportive impact on European coal prices of declining European coal mine production.

Tough Times For US Coal
Peabody, Arch Coal, Alpha Natural Resources Share Price, Rebased as of January 2009 (LHS) and US Coal Exports & Imports, million short tonnes (RHS)

The EU's renewed interest in coal, in theory, is likely to be reasonably short-lived, owing to EU regulations governing large power plants. The EU Large Combustion Plant Directive applies to all combustion plants that are equal to or greater than 50MW in capacity - and aims to restrict the level of emissions omitted from combustion plants (including sulphur dioxide, nitrogen oxides and dust). The directive requires plants built earlier than 2007, to either comply with the emission standards or 'opt out' of the scheme. The decision to opt out is only available on the condition that the plant will operate for no more than 20,000 hours between January 2008 and December 2015 - and then fully close by end-2015. In the UK alone, the national grid reported that, as on January 2008, 11,550MW of capacity (consisting solely of oil and coal-fired power plants) chose to opt out of the Directive.

However, despite this, a number of utilities are rushing to bring coal-fired projects online, to profit from the cheap prices of coal. Germany, for example, has a surprisingly strong coal-fired project pipeline considering its green energy policy promoting the widespread use of renewable technology. It has been reported that two new coal plants were commissioned in Germany in 2012 and six more were due to open during 2013 - with combined capacity of nearly 6GW. However, the outlook for coal-fired power plants post 2016 is uncertain, particularly given that technology that would help reduce emissions, and thus comply with the EU Directive if incorporated into the facilities, is expensive and lacking widespread uptake.

Combined Heat and Power (CHP) power plants, i.e. the simultaneous production of both heat and electricity, is actively encouraged by the EU as a means to boost efficiency and reduce emissions in line with the EU standards, however the technology is expensive and a number of countries in the EU are having to turn to national subsidy schemes in order to support the technology. Carbon Capture and Storage (CCS) could also be proposed as a way to tackle the emissions quandary, however we have previously commented on the lack of progress of CCS technology, maintaining our long-held view that the technology represents nothing more than a high-cost abatement option (s ee, 'Sole Bid Further Undermines CCS', July 10).

Gas Uneconomical

Turning to gas prices, and the future of gas-fired power generation, the picture continues to be shrouded in uncertainty. It is simply a case of economics in our opinion; if the price for gas is not competitive then we see little movement away from coal as the choice feedstock.

Gas Price Snapshot
Natural Gas Price In Selected Markets, 2007-2012 (US$/mnBTU)

There are a number of different factors that have the potential to effect gas prices in Europe; however we are not overly optimistic about any of them having significant downward pressure on prices, within this side of the decade. These include shale gas, domestic conventional production, pipeline gas and Liquefied natural gas (LNG).

  • Conventional production: In terms of ramping up domestic conventional production, we do not see much potential (excluding Russia) - with production on the down-trend in many countries, particularly the UK. Notable exceptions to this would include Romania and Bulgaria - however we do not believe this would provide enough supply to shift the pricing dynamics currently at play.

  • Shale Gas: Commercialising European resources of shale gas may not be as straightforward as initially thought - especially for those who believe the industry will follow a similar positive trajectory to that of the US' unconventional sector. Using Poland as a case in point, despite the government's enthusiasm, shale gas exploration has been hit by below-ground difficulties, compounded by a shortage of oilfield services to adequately support operations. Public opposition against hydraulic fracturing (fracking) on environmental grounds have also obstructed early explorations in Ukraine, UK and Romania. The lack of a clear legal framework to safeguard against fracking will no doubt stall commercial shale gas production within the decade, and therefore delay any sort of prompt in cheaper gas prices.

  • Pipeline gas imports: Gas supplies from Azerbaijan will likely flow into Europe via the Trans-Adriatic Pipeline (TAP) in 2019. While this helps Europe to diversify its sources of gas supplies away from Russia, the relatively small amount that TAP would carry initially (about 17 bcm) is only about a tenth of Europe's total gas imports from Russia. Therefore, there would not be sufficient pressure to force Russia to significantly reduce the price of gas sales. Additionally, the high cost of Azeri gas production also limits the extent to which its producers can discount gas prices relative to Russia.

  • LNG: Despite excitement that the start of US LNG exports from the late 2010s would see a fall in gas prices, our Oil & Gas team does not expect Europe to significantly benefit from this. Government regulations would likely restrict the amount of LNG flowing out of the US into the global market, and as such, volumes could be too small for Henry Hub-indexed US gas supplies to materially affect global gas prices. In fact, the expected rise in both domestic and external demand for US gas (which is expected to outstrip US gas production growth) would likely see an increase in Henry Hub spot price towards the latter end of the decade. After liquefaction and shipping costs have been accounted for, US LNG supplies could cost around US$10-11 per million British Thermal Units (mnBTU) - which is around the average price Europe currently pays for gas.

Already we have witnessed a substantial amount of gas-fired capacity being mothballed on account of the conditions within the market, making such projects unprofitable. A situation that is only likely to worsen if gas prices remain high. In addition to this, gas is the preferential feedstock to be used as a 'back-up' to renewable energy, in order to maintain stability of the grid. Therefore, the sheer influx of renewables capacity onto the European grid over the last decade has left existing gas-fired power plants with very low utilisation rates, again resulting in lost profits for utilities operating those plants. The International Energy Agency has stated that gas plants require a utilisation rate of 57% to be profitable. For example, E.ON's Irsching 5 gas facility, which cost US$523mn to build in 2010, is reported to have been dispatched for around 2,000 runtime hours in 2012, despite being designed to operate for 4,000 hours a year (see 'Irsching May Set Short-Term Precedent', May 16).

With this situation in place, whereby many companies are choosing to mothball gas-fired facilities due to questionable economics, large-scale coal-fired projects are scheduled to be shut down by 2016, and the cost of nuclear being prohibitive, we believe the risk of a power crunch in Europe is not out of the question. Even if the media's rhetoric of widespread European 'black-outs' may be far-fetched, we do caution that without some sort of policy alteration, the chaotic situation in the EU energy space will persist, leaving utilities in continued doubt over how to operate within the market.

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This article is tagged to:
Sector: Oil & Gas, Infrastructure, Renewables, Power
Geography: Europe, Europe, Germany, United Kingdom, Europe, Europe
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