Power: in demand?

All the current evidence supports growing power consumption, such as the drawn down in coal stocks reported by Genscape and data from the Edison Electric Institute, which reports that total US electricity production is currently 4% higher than it was in 2009. While this is no doubt welcome, the 4.3% YoY decline recorded in 2009, means that a significant recovery is needed to return the sector to the profitability it enjoyed in 2008. Small wonder then, that Fitch Ratings currently has a near to medium term outlook for the industry. It predicts that high natural gas supplies will keep power prices down over the 2010-2012 period, combined with reserve capacity margins which are projected to remain above average over the next three to five years and expectations of only a moderate cyclical uptick in power consumption. Profitability could be impacted by the introduction of painfully tight MACT standards and the roll off of current wholesale electricity hedges. On the other hand, the situation has provided the industry with vital breathing space. If the US had continued with the growth trajectory seen back in 2007, then meeting the growing demand for power would have been an uphill struggle at best. Currently, the North American Electric Reliability Corp. (NERC) is projecting that the summer peak demand margin across North America will be 28.6%, up 3.2 percentage points higher than in 2009 and up 7.2 percentage points from that seen in 2008. It also reported that lower economic activity was the primary reason why summer peak demand this year is down 2.2% from the forecast made back in 2009.

While the recovery remains fragile and unemployment is still high, power demand is rising, partly thanks to higher than average temperatures.

In terms of individual utilities, the situation is broadly in line with the national figures. Southern Co has recently reported a 4% increase on year in its 2Q10 power sales, with a 12% rise in electricity sold to industrial users. However, demand from smaller commercial users fell by 1%. Adjusting the figures for hotter weather, underlying residential consumption rose by 1.4% in the same period. Despite the gains, the company’s total electricity sales remain 6% below that seen in 2Q07, prior to the financial crisis. As far as other utilities are concerned, Dominion Resources has seen a 5.2% increase in electricity sales in 2Q10 on year, led by a 7% rise in industrial demand, while  Exelon Corp has seen a more modest recovery.

Looking towards the future, as of May, Barclays Capital expects US power consumption to rise by 1.5% this year, on the back of a 6.1% increase in industrial output, while the EIA is predicting a more bullish 3.5% YoY advance for the second half of this year, due to high temperatures, along with a more moderate 1.1% rise in power demand in 2011. Fuel costs are expected to grow by 0.8% over the course of this year, with price inflation effectively capped by high inventories, which will be largely eaten away by 2011.

Fuel of choice?

2010 is expected to feature a marked slowdown in the rise in fuel switching from coal to natural gas, courtesy of rising gas prices and high coal inventories. Consultancy Bentek Energy expects the growth in natural gas consumption by power utilities at the expense of coal to be just 50% of that seen in 2009, assuming an average gas price of US$4.25/mBtu for the whole of this year. According to Bentek, last year saw 1tnft³ of incremental gas demand arising from coal to gas fuel switching in 2009, while data from the EIA indicates that electricity production from natural gas fired units rose by 5% between 2008 and 2009, while that from coal-fired plants fell by 12% over the same period. The proportion of natural gas in the US thermal power mix has grown rapidly in recent years. In 2007, the EIA put it at around 30%, rising to 45% in 2009. Analyst disagree about the exact price where switching from coal to gas becomes economical, but most suggest a number in the US$4-5/mBtu range. As of its July 6 short-term outlook, the EIA was predicting an average natural gas price of US$4.70/mBtu for 2010, up US$0.75/mBtu from 2009.

Although this is mildly encouraging for those in the coal industry, who are no doubt already enjoying the demise of federal cap and trade, there are still storm clouds looming on the horizon for coal-fired generation. Chief of them, is the recent Clean Air Transport Rule (CATAR) put forward by EPA, which is aimed at tightening up SO_x and NO_x emissions for the 31 states and the District of Columbia, which lie upwind of other states and therefore effectively export their air pollution outside their natural jurisdiction. The proposal calls for a 71% reduction in SO_x emissions from 2005 levels over the painfully narrow 2012-14 period, with a similar timetable laid out for a 52% cut in NO_x emissions. According to a research note from Barclays Capital, the states that will see the largest shortfall in SO_x emission allowances are Pennsylvania, Georgia, Ohio, Indiana, and Alabama, while those that will have to make the largest cuts in percentage terms are Massachusetts, Maryland and Delaware. In terms of the affected states’ coal-fired power plant fleet, it reports that 69% already have scrubbers installed, leaving operators with a rather unenviable decision regarding the remaining 31%. Given expectations of further environmental legislation in future, it makes little sense to install new equipment in the oldest plants, but operators may not simply be able to shut them down due to commitments in the form of power purchase agreements, potentially eating into profitability. EPA expects the move will raise electricity prices by 2% and cost the industry US$2.8bn a year, while at the same time saving the wider economy US$120-290bn a year in avoided pollution, respiratory complaints and heart attacks.

While the recent declines in the value of EUAs have shown that the market mechanisms are mature and responsive to changes in the demand/supply balance, they are unlikely to provide sufficient incentive to reduce emissions and switch to lower-carbon technologies such as renewables and CCS. To a certain extent, this is a short-term issue given that the market is expected to tighten significantly going into Phase III in 2013-2020, due to tighter emissions caps and a move towards full auctioning of allowances. Unfortunately, for those in the nuclear and clean tech industries who are looking for a strong carbon price signal, there is the issue that EUAs are bankable from one phase to another. This means that the excess EUAs in circulation created by the recent recession, which lowered Eurozone fossil fuel emissions from industries under the scheme by 11.6 per cent to 1.873bnt in 2009 will not dissipate overnight, particularly if the move towards financial entrenchment and austerity measures being adopted by many European governments is taken into consideration. Bank of America Merrill Lynch has predicted that Phase II of the EU ETS will finish with its participants holding 166m surplus EUAs. To put this into some perspective, the European Commission recently announced that the maximum number of permits that will be permitted under the ETS in 2013 will be 1.927bn, based on a formula in which there will be a 1.74 per cent annual reduction from the yearly average seen in phase II. This figure is only for the currently-affected industries, with data for the entire scheme expected to be released in September and is expected to be frequently revised. The fact that the number of permits that will be available to new entrants such as aluminum production and aviation, is being worked out separately, should to a large extent shield existing participants from the rise in demand for allowances created by their introduction.

Some EU countries saw their emissions drop dramatically in 2009 due to the economic crisis, such as Estonia (-24%) and Romania (-18%). This meant that their industries were effectively overallocated carbon credits. Romania, Italy and France saw the largest windfalls resulting from the scheme.

In light of the above, there are two quick and dirty fixes that the EU can introduce. The first is the recently proposed shift to a 30 per cent cut in Eurozone carbon emissions by 2020 compared to 1990 levels, while the second is the introduction of unilateral or EU-wide carbon price floors, as are currently being proposed in the UK. Both would serve to drive the price of carbon up to a point where the EU ETS would start to achieve its intended purpose. Of the two, the latter would provide more certainty to investors, but if widely introduced would undermine the concept of a carbon market and would increase the argument for a simpler and easier to regulate carbon tax. Any approach designed to result in a stronger carbon price signal will be fiercely resisted by industry, given fears of a double-dip recession and the impact on Europe’s international competitiveness, but it is clear that there is growing momentum for a move to the 30 per cent cap.

In a joint initiative, the UK, French and German climate change ministers  announced on July 15 their support for the more ambitious target and Chris Huhne, the UK’s Energy and Climate Secretary said that: “We’re determined to make the economic case for the EU to cut its emissions by 30 per cent by 2020 as quickly as possible. Moving to a low carbon economy can help deliver energy security and contribute to economic recovery… The current 20 per cent target is not sufficient to encourage companies to make the necessary investment in green technologies and green jobs. The ‘wait and see’ policy of sticking to 20 per cent risks putting Europe in the global slow lane of maximising low carbon economic opportunities.”

Just as the UK has historically paid the price for being the first nation to undergo the industrial revolution, thanks to the inertia created by old and obsolete manufacturing facilities, so its early development of large-scale power infrastructure is starting to come home to roost.

According to the National Grid, two nuclear power plants are due to close next year, with a combined generating capacity of 1550MW, followed by nine oil- and coal-fired power stations in 2016 (with a total capacity of just over 12GW), equivalent to 16 per cent of the country’s total generating capacity. The latter wave is due in part to the EU’s large combustion plant directive. The situation is likely to put pressure on the remaining nuclear plants to continue operating, as witnessed by comments made at Marketforce’s Nuclear Industry Forum by a Westinghouse representative, that although its Springfield site had finished magnox fuel production, they were still getting phone calls asking if it could be resumed. It is worth bearing in mind that this could start to undermine public support for nuclear, particularly if the ageing fleet experiences radiation leaks in a manner similar to the Vermont Yankee reactor in the US. There is also the problem of reliability. Although British Energy successfully managed to return four reactors to service last year after repairs to their cooling systems and wiring, one of the reactors at its Dungeness plant has been out of action since November 2009. As the plants continue to age, it is inevitable that further repairs will be needed.

The UK's early adoption of nuclear power means that many of its existing reactors are coming to the end of their planned working lives and will soon need to be decommissioned.

A related problem is the fact that there appears to be a GBP4bn “black hole” in the government’s budget for handling nuclear decommissioning and waste costs. To put this into some perspective, the Department for Energy and Climate Change’s annual budget is currently around GBP3bn. This issue does serve to highlight the potential long-term issues with new build, although it should be noted that a large proportion of the costs have resulted from the UK’s military nuclear legacy.

One of the developments that is looking increasingly likely, particularly given government insistence of no direct subsidies for nuclear and the lack of a clause requiring EDF to build new nuclear plants after its acquisition of British Energy, is a move to a carbon price floor, as discussed by the Minister of State for Energy Charles Hendry at Marketforce’s Nuclear Industry Forum (click here for highlights of his speech). He told the delegates that it would be introduced as quickly as possible and is currently under consultation. The main issue is likely to be getting the floor price right, given that regular adjustment would undermine its purpose of providing certainty for investors. Given the potential for nuclear bill costs to spiral upwards, as demonstrated by Finland’s woefully over-budget Olkiluoto 3 reactor, if the UK government is serious about new nuclear build and a shift towards greater use of renewable energy, erring on the high side could well be prudent.

IFandP: If you could make one change to the UK’s education system, what would it be?

TB: Starting with the hard questions first, I see! I would ensure that employers have a greater role as stakeholders in education. In my opinion, there’s a substantial opportunity, given that a new government means a new philosophy. We’ve had 15 years of government telling the education sector what it should be doing. There are two main drivers: policy and funding. The previous government was committed to this issue, employers essentially were encouraged to chase funding, but what they wanted was more support for bite-sized learning. There is a lot of public funding available for technical skills (about 40 per cent), but arguably companies would have paid for this in any case. The current system has effectively created a network of brokers and failed to boost productivity.

IFandP: What do you expect to see from the new coalition government?

TB: The most positive aspect of the new government from our perspective is that it seems hell-bent on taking out the bureaucracy that is stifling employers, such as the huge institutions that have been set up just to quality control the information that employers are sending back. What should be quality controlled is the quality of training. It is a bit early to get a full perspective of what might be in store, but an expected move towards addressing unnecessary complexity would be welcome.

IFandP: Is there more that could be done to raise the profile and status of energy workers in general?

TB: Absolutely. Currently, the industry has a low profile with schools and universities. Engineering is still perceived by many as a dirty job done by people with spanners. The drop in popularity of many key subjects such as maths is an issue, while some qualifications are starting to be questioned by employers. Essentially, engineering needs to reinvent itself. Energy and the environment, these are the things that appeal. Young people want to make a difference and the energy sector is absolutely ripe for “hero” engineers in the mould of Isambard Kingdom Brunel. We need to invent the green technology to support a transition to renewables by 2050. Employers have to work with their competitors to build a supply of students and then compete for them. There is also a clear need to develop better relationships with school, explaining to them what we want and showing the sector at its best. More dialogue is needed and once you’ve got it, you’re away. Essentially we need dialogue, which responds to the needs of the energy sector.

However, the Kingdom need not go down this path. Its wealth could be channeled into new nuclear build and the fact that the desert sun delivers around 7000W/m² over an average of 12 hours a day, means that it has vast potential from the perspective of solar power. This could well enable Saudi Arabia to go on exporting energy long after it ceases to be one of the world’s largest oil producers.

There are unfortunately, significant barriers to such a vision. The country lacks the skilled and educated workforce needed for a large-scale nuclear build programme. There is also the fact that all key decisions relating to such a programme would have to be made by King Abudullah, who is not known for his speed when it comes to nuclear issues. Saudi Arabia signed a comprehensive nuclear safeguards agreement with the International Atomic Energy Agency in 2005, but it took almost four years before the Kingdom brought it into force.

Growing pains

According to the latest forecasts from Report Linker, the country is expected to see a increase in generating capacity of 38.2 per cent over the 2009-2014 period, on the back of expectations of real GDP growth averaging 3.36 per cent per annum over the 2010-14 period. The sums are impressive. According to a recent estimate by Saudi Arabia’s Banque Saudi Fransi, investment in the Kingdom’s power and water sectors will need to rise by around a third to US$266.7bn through to 2025, compared to the total investment of US$400bn planned for total infrastructure. So far, SAR300bn (US$80bn) has been budgeted for new generating capacity.

The Saudi power sector remains essentially closed, with little effort being made towards privatisation and still dominated by the largely state-owned Saudi Electricity Company (SEC). In addition, its regulatory environment is somewhat poor, with Business Monitor International (BMI) rating it below Iran’s. However, BMI in its updated Power Business Environment ratings, puts it in fifth place worldwide, due to the considerable size of the market, high energy independence and low current use of renewables. It also expects electricity consumption per capita to rise by 22 per cent over the next four years, while total power consumption is forecast to rise to 257TWh by 2014, from the estimated 189TWh seen in 2009. In addition, SEC expects generating capacity will need to be increased from the current 45GW to 70GW by 2020 or around 3GW every year. The driving force behind this rapid increase is a combination of the country’s reliance on desalination plants for its drinking water, rising demand for air conditioning and expectations that GDP per capita will rise by 42 per cent over the same period. There is also the fact that the Kingdom’s population is rising rapidly. According to the Population Reference Bureau, the current population of 28.7m will increase to 35.7m in mid-2025 and 49.8m by mid 2050.

After initial introductions by David Saunders, Managing Director of Marketforce, and Eamonn Butler, Director of the Adam Smith Institute, the conference started with opening remarks from Doug King, Vice Chairman of Deloitte, who gave a summary of the major events that had happened in the industry in the past year. Volker Beckers, CEO of RWE npower (RWEGn.DE), followed, discussing the unique scale of the investment challenge facing the UK. He warned that GBP200bn was needed to replace key power and water infrastructure over the coming decade and that this figure becomes more daunting when one considers that it is roughly equivalent to the market capitalisation of the major utilities. It also comes at a time when global competition for capital “is at unprecedented levels. He pointed out that “recession may mean that the cliff edge is further away, but it is still there,” referring to the breathing room created for the power sector by the reduction in demand triggered by the recession. Mr Beckers also called for a clear “energy contract” between governments, consumers and utilities, which in his view would help to create the certainty needed to drive investment in the sector. This would also be the responsibility of the government, particularly in terms of enabling CCS and renewables, while utilities would absorb the construction, operational, commercial and market risks, “provided that they are in a predictable framework.”

The topic was later picked up by Ian Marchant, CEO of Scottish and Southern Energy (LSE: SSE), who pointed out that although the idea was intriguing, any contract between three parties is hard, especially in such a fragmented market. He made the point that in his opinion, the government should use the tax and social system to tackle social issues, not the energy industry.

Mr Beckers then expressed some concern about the dangers of companies setting different standards for smart appliances and their control functions and the need for them to effectively link with smart meters. When asked by a delegate from Siemens, as to how to energy companies could incentivise customers to invest in energy-efficient appliances, he argued that it easier to deal with industry in terms of codes of practices then trying to effect change via dialog with consumers.

Mr Marchant ,in response to a question on heating, highlighted the need for district heating, commenting that such systems currently provide two per cent of UK heating demand, but this could be increased to 16 per cent and that every new development should consider it. Philip Green, CEO of United Utilities, followed with a talk on the challenge facing the UK water sector and the many achievements that it made in the past few decades. After a quick question-and-answer session, Dieter Helm, Professor of Energy Policy at Oxford University, gave a interesting presentation, in which he raised the point that there needs to be more debate regarding the objectives of UK carbon policy. He also argued that in general, market-based instruments were more efficient than having the government pick “winners” particularly in terms of the energy mix. He poured scorn on the 20 per cent renewables by 2020 goal, saying that it puts overwhelming emphasis on offshore wind, which currently is extremely expensive as are the devices currently in place to deliver it, such as Renewables Obligation Certificates. Professor Helm went on to explain that efforts to introduce CCS in the UK could well be threatened by the rise of unconventional natural gas, which could significantly reduce the economic appeal of coal-fired power generation. Another topic that he addressed was the issue of new nuclear build, putting the case that it is significantly discriminated against compared to wind, which receives both subsidies and long-term contracts. In his view, Professor Helm sees future moves towards a lower carbon economy as being a shift towards natural gas as the fuel of choice for power plants in the short-term and the adoption of the electric car in the longer term. He concluded by arguing that the framework of such discussions needed rethinking as “It’s stupid to worry about security of [natural gas] supply when supply is being revolutionised.”

Venkie Shantaram, partner at Mckinsey & Company, alluded to the perfect storm facing the UK, in terms of its shrinking resource base, global competition for oil and gas, together with financial constraints, environmental factors and flat demand. He emphasised the declining importance of the North Sea, which at one point provided 69 per cent of the UK’s oil and gas needs. This percentage is expected to decline to just two per cent by 2030. He predicted that LNG imports would rise quickly and made the point that nuclear new build was the most critical issue facing the UK’s energy sector. Mr Shantaram made the observation that “No nuclear plants are built by private organisations in fully-liberalised markets. We’re the only [such] country expecting this. After commenting on the twin issues of the scale of investment required and the uncertainty surrounding future natural gas and CO₂ prices, he turned the focus of his talk to the increasing use of “inflexible technology” with higher upfront capital costs. Mr Shantaram pointed to Spain, as an example. The country currently has 49GW of wind power and at some points, electricity prices have dropped close to zero as a result of high winds, while at the same time CCGT utilisation has dropped by 25 percentage points, with the implication that increased penetration of renewables reduces the profitability of thermal generation and that there needs to be a mechanism to compensation operators of thermal power plants, in order to keep such systems available for the purposes of grid stability.

In terms of CCS, Mr Shantaram made an analogy with the North Sea, in that it was initially seen as a harsh environment and investment failed to materialise until the government erected the right framework and provided guarantees. He went on to say that it was too late for the UK to become a leader in CCS technology but other technologies have a great deal of potential, such as electric vehicles and energy storage.

John Saunders, CEO of the IPC, made it clear that his organisation will continue in its task of streamlining the UK’s often torturous planning process, regardless of the result of the forthcoming election.

An interactive session then followed, in which delegates were able to express their views on the most important issues for the industry. Forty per cent believed that political indecision is the most significant barrier to achieving 2020 targets, while 20 per cent of those polled believe that the targets are unachievable. A narrow majority (58 per cent) believe the Infrastructure Planning Commission (IPC) is the long-awaited solution to the current protracted planning permission process, while a worrying 78 per cent feel that the British government will need to allow derogations from the European Large Combustion Plant Directive in order to stop the lights going out. Exactly half of the delegates believe that a carbon floor price is necessary for the investment case for low carbon generation, rather than separate obligations or incentives by sector. Roughly the same proportion (54 per cent) wanted to see a carbon price floor of EUR40-60/t, with 28 per cent thought EUR20-40/t would be better while 11 per cent voted for the EUR60-80/t range. Sixty-five per cent of the audience thought that the government was not doing enough to encourage CCS and 75 per cent thought that regulators were not doing enough to incentivise investment in critical investment infrastructure.

The subject then turned to CCS and renewables. Rupert Steele of Scottish Power, commented that the current CO₂ price system “doesn’t really work”, given the lack of visibility going forward and said that it is not the right thing for nuclear. He also pointed to the future huge requirement for backup generation if the UK starts to approach the proportion of renewables in its generating mix mandated by the 2020 targets. He also said in response to a question that he was absolutely delighted to be selected for the next phase of the CCS process and that Scottish Power is in the process of drawing up blueprints, with the goal of converting an old natural gas feeder line into a pipeline capable of storing CO₂ in a old gasfield, in co-operation with Shell and partners, with the goal of having it up and running by 2014. He also commented that they had already found a way of reducing the energy used by CCS by “about a third” and that more efficiency gains are expected to be made as the technology continues to mature.

Alan Raymant, Chief Operating Officer of Horizon Nuclear Power, was more upbeat, suggesting the current situation presents “hugely exciting opportunities,” while at the same time calling for the low carbon nature of nuclear power to be recognised. He was followed by Matthias Haag, CEO of Aquamarine Power (see our recent article, “Scotland makes some Waves”), who said that he thought the UK government in general had been extremely supportive of marine energy, but the industry still needs more equity, as the current system, while good for developed technology in his eyes, was not fully appropriate for wave and tidal power, given that these are still in many cases at the pilot project stage. He also said that in his opinion, the Renewables Obligation Certificate supporting scheme is very good, but it needs to be equalised, as there are currently different schemes in Scotland and England.

John Saunders, Chief Executive of the Infrastructure Planning Commission, gave a presentation in which he explained how the new planning system would work, describing it as a “more managed process” and saying that it will be accountable to parliament and challengeable in the courts. He emphasised that the IPC is “ready for business” and stated that in contrast to some recent press coverage, the Conservative Party is moving away from the idea of dismantling the IPC, instead apparently considering its merger with the planning inspectorate.

In the fourth session, Mike Calviou, Director of Asset Management for the National Grid, gave a fascinating overview of the current outlook for T&D projects in the UK. In particular, the sheer scale of new wind farm additions, calls for a significant amount of new transmission lines, both on and offshore. This includes grid reinforcements to accommodate increased transfers from Scotland and North Wales. On the subject of natural gas storage and entry connections, Mr Calviou predicted that the network would see increased volatility. He also commented that there are currently a large number of LNG importation and gas storage projects under consideration. This in our view, could significantly reduce fluctuations in UK gas prices and result in lower prices, should they materialise.

The Future of Utilities conference proved to be time well spent. In addition to the discussion summarised above, it featured excellent networking opportunities in the impressive Guoman Tower Hotel, complete with a spectacular view of London’s Tower Bridge. With a further two days of discussion, presentations and cutting-edge insight from the best minds in the industry, it certainly lived up to the high standards delegates have come to expect from Marketforce conferences.

Ecuador was spared the worst of the global financial crisis and the following recession. Although one would think that given the country’s heavy focus on its oil industry, the rapid drop in oil-based revenues would have acted as a brake on growth, the country’s economy shrank by just 1.4 per cent in 2009. Current projections are for a mild return to growth this year, with the IMF predicting an increase in GDP of 1.5 per cent. The fact that oil prices have recovered substantially since early 2009 is encouraging, particularly given the increased need for state intervention in order to create lasting growth. A real issue has and will continue to be the country’s exposure to the US economy, which is currently home to over 1m expatriates and is one of Ecuador’s largest trading partners.

Ecuador’s power utilities are starting to feel the strain, thanks to a combination of high level of debt and the fact that electricity demand grew at a CAGR of around six per cent over the 2002-2008 period primarily spurred on by rocketing residential demand. Some breathing space was gained as a result of the recession, with demand dropping in 2009. In addition, it is now projected that the pace of future growth in electricity consumption will be lower at around 3.8 per cent per annum for the 2010-14 period. The main drivers behind past and future growth appear to be a buoyant construction sector, coupled with a continuing shift towards greater urbanisation.

The structure of the market

Ecuador’s electricity sector is predominantly state controlled. At present it consists of the regulator Conelec, which was set up in 1999, the Centro Nacional de Control de Energía (the national centre for the control of energy), together with 13 power companies, one transmission company and 20 distribution companies. The country’s total generating capacity in 2008 stood at 4307MW, relatively unchanged from that seen in 2007. Grid management relies extensively on electricity imports, particularly from Colombia. Typically total imports account for around 15 per cent of demand.

Ecuador’s buoyant construction sector and rising urbanisation are pushing electricity demand upwards

The high level of state involvement is something of a weakness, in the context of the current political situation. President Rafael Correa’s party, the Alianza País (AP) lacks a legislative majority and this combined with political pressure from the conservative opposition and the damage done to the government’s fiscal standing by the recent recession will make it hard for the state to deliver lasting improvements in this area. The need to continue operating at a fiscal deficit for 2010 in order to prop up the economy also restricts room to manoeuvre and while as mentioned earlier the rebound in oil prices will help Ecuador’s economy, the low levels of investment in the energy sector, resulting from the financial crisis will mean that oil output is unlikely to rise over the course of this year. Private companies involved in the country’s power sector such as Odevrecht and EDC have found themselves locked in lengthy contract disputes and payment delays. This poor commercial environment is effectively forcing the government to finance the majority of all infrastructure projects in the power sector.

A real issue, as is the case for many countries in Latin America is the reliance on hydropower, in the context of frequent dry spells that can result in significantly reduced power output. Utilities have taken a number of measures designed to reduce the impact of this such as building back up reservoirs and adding additional capacity. However, the situation is still one of the major drivers behind the country’s need to import electricity, especially from Colombia. The country’s reliance on hydropower led to power rationing being introduced in September 2009, thanks to one of the worst droughts in 45 years. This severely impacted on the 1075MW Paute dam, which is the largest of its kind in the country. By November, the situation was such only two of its 10 turbines could function, reducing its output from 20,000MWh to just 4000-5000MWh. The power rationing was eventually stopped on January 20th 2010 and since then reservoirs have returned to normal levels thanks to high levels of rainfall. The combination of reduced supply and power rationing reduced electricity consumption by four per cent during the November to January period and is estimated to have cost the commercial sector US$250m in lost business. Around the same figure according to President Correa was invested to help resolve the crisis.

The power crisis may owe its roots to more than just a lack of rainfall. Ecuador suffered from a severe economic crisis back in 1999/2000, which triggered a six per cent decline in GDP and forced the country to default on its external debt. Investment rapidly dropped off as a result and a lingering aftershock from the crisis was a massive increase in the poverty rate and this led to the imposition of a windfall tax on foreign oil companies in 2006, which led to reduced oil production in 2007. President Correa also threatened to default again on the country’s debt in December 2008 and levied a further windfall tax on the oil companies. As a result, private investment declined significantly in 2009. In addition, the political environment, along with unstable regulations and corruption has lead to Business Monitor International labelling it the most risky country in the region from the perspective of investors. In such a context, it is clear that Ecuador’s power sector has struggled to obtain the levels of investment needed for modern equipment and the capacity additions necessary to support further economic growth. Indeed, during the height of the crisis, President Correa took pains to cast previous governments as the cause, saying that it was the consequence of twenty years of not investing in electricity.

Interestingly in October 2009, Luis Castelo, a senior official at the country’s ministry of electricity and renewable energy (MER) said that the government was looking to boost the proportion of hydropower in its generating mix to 80 per cent by 2020, up from the current 43 per cent, despite “a lot of resistance from the indigenous communities.” A further 10 per cent would come from renewables, so that if the plan comes to fruition, the country would only look to fossil fuels to supply 10 per cent of its electricity. Part of the rationale behind this goal is the need to reduce Ecuador’s reliance on diesel imports, as despite being a major oil producer, the country lacks refining capacity needed to meet current demand. MER has also made the point that a switch to greater use of renewables would free up more oil for export. Its figures include that the program would allow Ecuador to export around 86Mta of oil, raising over US$5bn in revenue for the country.

The new drive to boost the country’s hydropower capacity is the rationale behind the Zamora hydropower project, which was announced by Ecuador’s Minister for Coordination of Strategic Industries Galo Borja in February 2010. The US$6bn, four dam project, with a combined generating capacity of 4000MW is expected to be complete by 2016 and will be funded by state-run companies. However, the hefty price tag, together with the difficulty of raising finance, raises serious question marks as to whether it will ever materialise.

However, Ecuador may not be entirely committed to hydropower, as its government signed a memorandum of understanding with Russia on civilian nuclear power in August 2009. This included a measure affirming cooperation in terms of geological research, the development of uranium fields and also for the production of nuclear fuel and for the creation of a legal framework for Ecuador’s yet to be developed nuclear sector. Around the time of the MoU signing, President Correa commented that Russia might provide US$2.5bn in financing “for our strategic sectors,” without elaborating further. The government has also been discussing the possibility of new nuclear build with South Korea.

A clear signal that the sector is in real need of renewal is the fact that transmission and distribution losses are in the order of 21 per cent. In actual fact, several distribution companies have reported losses in excess of this, with Emelmanabí and Sucumbíos declaring losses of 36 and 35 per cent, respectively. The decision to split the national state utility network into many smaller companies has failed to result in higher levels of investment and it is thought that high level of government subsidy in the sector is compounding the issue. The high level of transmission losses was behind President Correa’s recent decision to put forward a law that would make power theft a crime.

There has been some recent progress on this front, with CNEL reporting that total electricity losses due to unpaid bills, theft and technical problems dropped in 2009 to 25.99 per cent, compared to the 30.16 per cent recorded in 2008. In order to try to reduce this figure further, it is planning to invest US$60.5m in the installation of 250,000 remotely controlled meters for residential consumers.

Current projects

President Rafael Correa has already signed a US$2bn contract with China’s Sinohydro, resurrecting the Coca Codo Sinclair 1500MW hydroelectric dam project along the Amazon River. 85 per cent of the finance will come from a Chinese bank and the remainder will come from sales of oil to China. Although Sinohydro’s expertise in large scale hydropower is well known, its participation does fit into China’s pattern of investing heavily in oil rich developing nations, as has been seen in Venezuela and Africa. Ecuador’s government was originally going to provide 70 per cent of the funding for the project with Argentina providing the remaining 30 per cent. However, the project collapsed due to an inability to raise the necessary finance and therefore Ecuador was forced to pay US$5.5m to acquire the Argentine stake from its state power utility, on September 14, 2009.

Other recent investments include the purchase of two power turbines from the US for a total of US$14m, using state funds. They are to be installed at the Alvaro Tinajero and Abibal Santos thermoelectric plants and will generate 42MW and 20MW, respectively. Alstom Hydro is supplying two generators to the US$400m 162.6MW Mazar hydropower project that is expected to come online this month (March 2010).

In October 2009, power utility Hidropaute floated a tender for the pre-construction study and design of the 327MW Cardenillo hydropower plant. The design is expected to be finalised in 2011. There is also the Topo hydropower project which has recently had its designed capacity increased slightly to 22.7MW, by Conelec. Proyectos Energía y Medio Ambiente is developing the plant, which is expected to be up and running by May 2012. However hydrological studies conducted in the mid 2000s, indicated that it could only produce 6-10MW throughout most of the year. The project is also controversial, given the high level of biodiversity in the affected area.

In related news, Ecuadorian and Mexican companies have signed a US$2m two year design contract for two hydropower plants on the river Guayllabamba with Russia’s Gidroproekt Institute, which has designed over 150 such plants. Meanwhile, power utilities Hidrotoapi and Energyhdine are currently looking into the possibility of tapping into national social security institute (IESS) funds to help finance their Toachi-Pilaton and Rio Luis hydropower plants.

In terms of fossil fuel-fired generation, there have been relatively few developments, which is unsurprising, given the country’s attempts to move away from it on strategic grounds. That said, a 90MW complex was launched in January 2010, in the western canton of Quevedo. Its capacity was expected to have been increased to 120MW by February, according to the local daily El Comercio. The generating units had been hired from a local firm, Procapet, by the government, under a six-month contract. The fuel costs expected to be incurred over this period are estimated at US$25m.

Building more hydropower dams could free up additional crude oil for export. The country’s oil wealth is also sparking interest from Chinese investors.

Will the water be there?

While Ecuador’s current hydropower resources are impressive, the recent events coupled with long-term concerns regarding the region’s climate in the context of global warming and further deforestation raises serious questions regarding the wisdom of dramatically expanding the country’s reliance on hydropower. While there is clearly a compelling economic case for freeing up more oil for export, relying on any one source of electricity to the extent the government is proposing has been shown to create major issues for the power sector. A good example is France, where around 80 per cent of the nation’s electricity comes from nuclear plants. Their inability to rapidly adjust to fluctuations in demand mean that the country is forced to often export electricity at very low prices and import it during times of peak demand.

In Ecuador’s case, while building much more hydropower capacity than the country currently needs could limit the downside of drought-induced declines in the load factors of individual plants, it is doubtful whether such an approach would be economic in the long run, even accounting for the potential to export electricity to its neighbours and the potential boost to oil export volumes. There is also the question as to where the necessary finance will come from, given the state of the country’s finances. However, China’s thirst for oil clearly represents a major opportunity, especially in the light of its growing reluctance to keep so much of its new found wealth in the form of US bonds. From Ecuador’s perspective, much would rest on whether what it receives from a such a deal will be fair value in the future, in the context of dwindling global oil resources and what would happen to overseas investment if China’s nascent property boom were to implode.

IFandP: What are ABB’s main power generation interests in the Middle East?

Ramesh Kumar: ABB has been one of the major players in the field of power generation for more than a century. We have one of the largest global installed bases and are technology leaders when it comes to power and automation backed by application know-how and domain expertise. We offer integrated electrical, instrumentation and control solutions on a turnkey basis with a proven track record in saving time, reducing costs and managing risk.

IFandP: What are some of the emerging power generation focus areas in the region?

Ramesh Kumar: With growing climate change concerns, the Middle East is actively looking into alternative energy sources like renewables and nuclear. Development of the carbon-neutral Masdar City in Abu Dhabi is one such example. The UAE is also making progress with nuclear power approvals.

IFandP: In terms of control systems for power plants, where do you see the envelope being pushed? Where is the bulk of your expertise concentrated in this area? Is it artificial intelligence or predictive control?

Ramesh Kumar: We have always been in the forefront of technology when it comes to energy efficiency and reliability of plants. ABB invests over US$1bn annually in technology development .Our flagship control system, System 800xA, is the backbone of our standard power plant control package. It is a state-of-the-art distributed control system (DCS) based on open communication standards and compliant with IEC 61850.

In terms of efficiency improvement, we offer customised modules for power plant generation. Some of the main customer requirements we strive to meet, include integrated technologies for unit and turbine control with integrated safety systems aimed at providing availability, redundancy and protection.

Increased care for operator efficiency achieved through advanced display and information management technology as a DCS integrated feature are other important factors to facilitate security of supply, productivity and plant safety.

IFandP: How concerned are your clients about the whole issue of security? I remember hearing once that in this day and age, power utilities may be becoming increasingly vulnerable to cyber-attack?

Ramesh Kumar: If you look at the control system for the power plant, it’s not generally connected at the moment to the cyberworld. We do provide consulting services combined with a system design that offers intrusion protection from internet to the plant DCS and also takes into consideration system features combined with appropriate processes and access controls.

IFandP: Where do you see the Middle East’s energy mix going forward? Do you seeing it almost being entirely renewable one day?

Ramesh Kumar: This is a region with a lot of hydrocarbon resources. So definitely the main source of power generation will continue to be driven by traditional fuel sources, but there is definitely a push towards increasing the share of renewable energy.

Solar is perhaps likely to lead the way in this respect. ABB has considerable experience and a range of power and technologies for solar plants. Andasol 1 and 2 and the Totana project in Spain are recent examples. In a solar plant, we supply all levels of electrical systems, as well as control and instrumentation solutions. ABB has also recently launched a DC to AC inverter for solar applications. Similarly, ABB has a complete range of offering when it comes to wind power.

IFandP: What sort of projects do you think you’ll be releasing over the next year or so, in terms of the power sector?

Ramesh Kumar: Hydrocarbon fuels, renewable energy and water plants and networks are likely to remain key focus areas. Our value proposition will continue to offer customers energy efficiency, plant optimisation and reliability as key deliverables.

IFandP: On the subject of high-voltage lines, there’s obviously the DESERTEC initiative, is ABB involved?

Ramesh Kumar: ABB is member of the DESERTEC initiative and one of the original visionaries. We continue to be engaged with the development of this initiative.

IFandP: Do you see carbon capture and storage (CCS) coming soon to the Middle East?

Ramesh Kumar: The relevance of CCS will depend a lot on global climate policies and agreements. Emission limits being discussed may mean that CCS first becomes relevant for fossil-fired plants using oil, coal, lignite or similar fuels rather than high efficiency gas fired CCPP. However a lot will depend on what emission limits etc. are set in the region.

IFandP: Does this pose any unique challenges?

Ramesh Kumar: CCS reduces plant efficiency to some extent, the major portion of this being an increase of the electrical auxiliary loads from these installations. This poses an optimisation and reduction challenge that needs to be addressed through plant automation and optimisation to a large extent. We have strong expertise in the field of oil and gas, where similar processes are in place. These will provide a good experience base.

IFandP: Obviously, there’s going to be a massive expansion of the world’s power sector due to the rise of China, the electric car and so on. Do you see it hitting a barrier due to the limited availability of raw materials, such as copper and rare earth metals?

Ramesh Kumar: We don’t really focus on this. We use the best available conductors, but our focus isn’t on the conductor itself or related materials.

IFandP: So your focus is more electronics?

Ramesh Kumar: We are a technology-based company. So development of technology for the improvement of power generation, transmission, distribution and utilisation is our key focus. We leverage our expertise in the field of controls, instrumentation and electrical systems to achieve these objectives. The application of power electronics, one of our core technology strengths, across the power value chain and the use of advanced communications will be important contributors. On the whole we strive towards “Power & Productivity for a better world”.

For more information regarding ABB and its range of products and services, visit www.abb.com

Brazil is in many ways a country to watch. Not only will it be the host to two major sporting events in the coming years, but major oil discoveries, coupled with the country’s extensive use of biofuels, suggest that it may soon see a dramatic increase in its wealth, with expectations that it will soon become the world’s fifth most prosperous nation, up from its current position at number eight. There will be challenges, such as the danger of the “oil curse” in which oil earnings inflate the value of a nation’s currency, making its other economic activities less competitive on the world stage. To some extent, an early form of this phenomenon is happening already, as witnessed by recent efforts to reduce the tide of foreign investment entering the country to a more manageable level.

On the flip-side, Brazil’s politicians, business leaders and financiers are and will continue to be faced with the problem of growing the country’s infrastructure as prosperity and population rise. In the power sector, the matter is compounded by the sheer scale of the Brazilian territory, which covers an impressive 8.51mkm². This has contributed to a situation in which 20m Brazilians living in remote communities do so in the absence of a reliable electricity supply.

As recently pointed out by Mauro Storino, a Fitch Ratings director, more investment in Brazil’s power sector is desperately needed given that the nation’s GDP growth has outstripped any increases in its generating capacity since 2005, while electricity consumption has risen by 52.9 per cent since 1995, compared to just 45.6 per cent for GDP growth over the same period. However, there is a concerted effort by the central government to address this issue in the form of the Accelerated Growth Programme (PAC) which, in the wake of the financial crisis of 2008, has turned into a key part of the government’s economic stimulus package. It will oversee BRL65.9bn (US$37.66bn) in investment in Brazil’s power sector over the course of 2010.

Figure 1: Brazil’ s conventional thermal energy mix by type (2007). Source: Ministry of Mines and Energy

Current demand

According to the latest data available from the Power Research Corp, Brazilian electricity consumption in October was the highest seen since December 2008, suggesting that an economic recovery may be in progress. However, at 33,722GWh, it is still down 1.1 per cent compared to October 2008 and 1.8 per cent down on the 12 months to October. In the first 10 months of the year, residential and commercial demand increased by 5.8 and 5.3 per cent, respectively, while industrial consumption fell back by 9.9 per cent. As a result, electricity consumption in 2009 breaks down to 42.5 per cent for the residential and commercial sectors and 42.9 per cent for industry.

Water: powering Brazil’s economy

Hydropower vastly predominates in terms of Brazil’s power generation mix, thanks to a large extent to the colossal 14GW US$17.5bn Itaipu hydroelectric dam on the Panama river. In 2008, it produced enough electricity to meet the entire world’s requirements for two days. The dam’s output is shared equally between Brazil and Paraguay, but the latter sells most of its power back to Brazil’s Electrobras, due to the lack of domestic demand. An agreement signed in the summer of 2009 will completely free Paraguay from its obligation to sell to Electrobras by 2023, allowing it to potentially sell at a higher price to private Brazilian utilities. Fortunately for Brazil as a whole, 2008 witnessed higher than normal winter rains, thanks to an El Niño effect. As a result, as of August 31, 2009, hydro dam reservoirs were 7-39 per cent fuller than in the previous year.

Hydropower accounts for over 85 per cent of Brazil’s generating capacity

This is not the end of the story. Brazil is benefiting from its neighbours and their drive towards new hydropower capacity. The most recent example of this trend is the proposed 800MW plant in Guyana, which is expected to begin construction in 2010, with a view to also supplying the north of Brazil by 2015. In addition, Brazil currently buys electricity from Venezuela’s Guri dam complex and a consortium of Brazilian companies led by Electrobras, are planning to build of 15 hydropower plants in Peru with a total capacity of 15,000-20,000MW. The first five are expected to come online in 2015 at a total projected cost of US$15bn. Financing will be partially provided by the Brazilian state development bank, BNDES. However, the projects appear to be moving slowly, partly as a result of security problems within the region and the sensitive issue of Inca relics. In addition, the Peruvian Amazon, where all of the projects will be situated, has seen considerable unrest as a result of oil and other development licences being granted at sites too close to indigenous communities.

Closer to home, GDF Suez SA, though its majority stake in Energia Sustentável do Brasil, a consortium that includes Brazilian construction firm Camargo Corrêa, is looking to build a 3450MW dam at Jirau, on the Maderia river in he state of Rondonia, at an expected cost of US$7.2bn. However, it has encountered resistance from local public officials.
As far as smaller and less contentious projects are concerned, ANEEL, the country’s national electricity agency and regulator, estimates that 1108MW of new hydropower capacity came online without any issues in 2009, with another 1357MW of projects either also being commissioned or delayed as a result of specific hurdles, while 99MW in the form of small projects faced “grave hurdles”

IFandP: Given the drain on the public finances of many countries resulting from economic stimulus packages and bank-bail outs, would it be fair to say that governments in the OECD will be sidelined in terms of investment, compared to the role of private utilities?

Dr Fatih Birol: In the near-term, many governments have actually stepped up their direct investment in some types of energy infrastructure and have increased incentives for private investment, especially in clean-energy technologies. But, clearly, in the longer-term, the need to reduce budget deficits can limit the scope for public investment. So, yes, a growing portion of times in the run-up to Copenhagen, many countries’ announcements are encouraging. Although more is needed to be on track with the 450ppm scenario in our World Energy Outlook 2009, current pledges, if implemented, are more in line with a 550ppm scenario (leading to a 3°C increase in global temperature)”. The IEA believes there is room for optimism given the growing political will globally. For example, the US EPA has recently identified carbon dioxide and five other greenhouse gases as dangers to public health and welfare.

IFandP: Given the clear need for rapid action called for by the WEO 2009, how do you think the rate of progress could be accelerated at both the national and international level? It seems clear that while democracy and a consultative approach are laudable, they may be ill-suited to the speed of response required to prevent runaway climate change. Given that the developed world is not going to adopt China’s political system, what can be done to create the consensus needed to get the job done?

Dr Fatih Birol: The energy path to stabilise climate is clear, but only vigorous action will put our economies on that path to green growth. Major technological and financial breakthroughs are needed. Right, timely and clear incentives need to be given to investors (and consumers). A strong political signal is needed now to drive the necessary changes. Stimulus packages can be prolonged well beyond economic crisis, which can provide additional clear signals of strong political will. Some of the current proposals include strong voluntary efforts as well as fund-raising addressed to developing countries in order to fight against climate change.

IFandP: Following on from this, should international organisations be working to reduce the influence of interest groups and lobbyists who might see the reference scenario as being in their interest?

Dr Fatih Birol: The role of the IEA is to advise our member governments on how to achieve their stated policy objectives and to facilitate policy cooperation among member and non-member countries alike. All our governments agree that we need to move away from the Reference Scenario and, through the World Energy Outlook and other activities, are showing them how they might go about achieving that.

IFandP: What response would you like to see from North American and European power utilities going forward?

Dr Fatih Birol: In the 450ppm scenario of the World Energy Outlook 2009, North American and European power utilities are implementing the cap and trade system with a CO₂ price reaching US$50/t by 2020 and US$110/t in 2030.

In the US, a substantial amount of coal-fired generation is replaced by gas-fired generation, as well as by increased renewables and nuclear generation. By 2025, with CO₂ prices going beyond US$50/t, about 30GW of nuclear plant additions will have been built, replacing substantial numbers of coal plants and non-hydro renewable sources will have increased almost five-fold over the 2010 levels. By 2030, electricity generation from renewables will account for 26 per cent of the total, nuclear for 25 per cent, gas without CCS for 24 per cent, CCS plants for 15 per cent (almost 90 per cent of which is coal-based) and coal without CCS only 10 per cent.

In the European Union, where the CO₂ price already in place gradually converges to the level for OECD+ countries as a whole by 2020, the adoption of lower carbon emitting technologies is accelerated relative to other countries and regions. Renewable sources account for most of the increase in electricity demand and contribute to displacing generation from coal-fired plants, which are mothballed or retired. Wind alone will account for 20 per cent of electricity generation by 2030, nuclear will see by 2030 an increase of around 20 per cent over 2007 levels. Generation from CCS plants is to account for six per cent of the total generation in 2030.

IFandP: Is it fair to say that as we start relying on more and more difficult to reach oil, the lead-time for projects will increase, making the industry as a whole more vulnerable to the oil price volatility seen over the past two years?

Dr Fatih Birol: The lead time for greenfield projects has been growing steadily in recent years as the focus shifts to more difficult terrain and to larger projects. That trend is likely to continue, though it may be offset by some degree by technological advances which may speed up the time it takes to bring new discoveries into production. Any further increase in average lead times would indeed make the market more vulnerable to price volatility.