Demand for power in the Middle East continues to grow, despite the slowdown in economic growth witnessed in some areas of the region in the wake of the global financial crisis. The UAE Energy Ministry has revised down its power demand growth forecast from 40,000MW to 33,400MW by 2020, but this still represents an 81 per cent increase on current consumption levels.
Elsewhere, Saudi Arabia is planning for annual growth of 8 per cent, while Qatar is expecting double digit growth every year until 2013, by which time total demand will have doubled to 7,791MW. Beyond the Gulf, Egypt is planning for annual electricity demand growth of 6.4 per cent, Jordan 7.4 per cent and Syria 7 per cent.
- 8 per cent: Estimated annual growth in demand for electricity in Saudi Arabia
- 19.5 million: Cubic metres of gas a day allocated for power generation and desalination in Oman
- $20.4 bn: Value of nuclear power contract signed in Abu Dhabi in December 2009
To meet these growth projections, the region’s utility providers are increasingly turning to the private sector through independent power and water projects (IWPPs) and independent power plants (IPPs) to ease the capital expenditure requirements of new capacity building. Raising project finance was difficult and costly in 2009 as financial markets seized up, but bankers say that financial terms are easing as the world economy begins to recover, and well structured projects, such as IWPPs should be able to secure finance this year.
“The appetite among banks for financing power projects is quite strong because this is an asset that is well identified,” says a senior Bahrain-based banker. “The track record of Abu Dhabi, Oman, Saudi and Qatar is impeccable. There is not a single IPP in default; there is not a single IPP which is being exposed to major delay, contrary to certain other projects.”
This did not prevent a number of schemes from struggling to raise finance in 2009. Saudi Arabia, for example, had to restructure its Ras al-Zour IWPP as an engineering, procurement and construction contract in mid-2009 after its bid consortium fell apart. Malaysia’s Malakoff withdrew from the Sumitomo-led group due to financing issues, and the consortium failed to find a replacement equity investor. But financiers say that the main problem in 2009 was the need to re-price deals, rather than the viability of specific projects.
“It hasn’t turned the corner yet, the cost is still high but it is starting to ease,” says Bob Bryniak, chief executive officer of the UAE’s Golden Sands Management Consulting. “By the time a number of projects come out towards the end of 2010 and into 2011, financing should be less of a problem.”
Efforts to find alternative feedstock sources will increase this year as the new gas allocations become harder to secure. With most readily accessible gas supplies already allocated internationally or domestically, additional quantities for new power generation and desalination projects are difficult to come by, prompting governments to consider building non gas-fuelled power stations.
The track record of independent plants in Abu Dhabi, Oman, Saudi and Qatar is impeccable
Senior Bahrain-based banker
According to the UAE’s Electricity Ministry, the country only has enough gas to provide 20,000-25,000MW of electricity, but peak power demand is forecast to climb to 33,400MW by 2020.
In Oman, the Oil & Gas Ministry has committed 19.5 million cubic metres a day (cm/d) of gas for power generation and water desalination. But in its 2009-15 forecast, the Oman Power & Water Procurement Company (OPWPC) says its gas requirements will reach 20.2 million cm/d or higher by 2015. Power demand is predicted to rise from 3,291MW in 2008 to at least 5,900MW by 2015.
The initial trend has been to opt to burn fuel oil instead of gas. Although not a new development – Saudi Arabia’s Council of Ministers ruled in 2006 that coastal plants should use heavy fuel as feedstock and reserve gas allocations for export-related activities – more power plants are expected to use heavy fuel oil in the future. For example, Abu Dhabi’s planned 2,600MW Taweelah C power project is expected to use fuel oil, although the scheme has been delayed in favour of the 1,600MW Shuweihat 3 which has secured a gas allocation. Sharjah, meanwhile, regularly burns oil to meet peak power demand during the summer months.
Both Oman and the UAE have been exploring the option of coal-fired power plants. In September 2009, OPWPC signed a technical and financial advisory for a 1,000MW coal-fired IWPP to be built at Duqm, while the UAE emirate of Ras al-Khaimah has looked at building a 4,000MW plant in Mina Saqr. The Ras al-Khaimah Investment Authority (Rakia) has even invested in coal mine projects in Indonesia to facilitate supplies.
However, sources say that both Rakia and OPWPC have abandoned their coal-fired ambitions. Developers are instead expecting Duqm to come to market as a traditional IWPP later this year, while Rakia has confirmed to MEED that its project remains on hold.
“My feeling is that we won’t see a coal plant in the Gulf because, firstly, the infrastructure is just not there to deal with it and secondly, there are real environmental concerns,” says Bryniak. “Countries that have coal, if they had a choice, would love to get rid of it. But it is has just not got the right environmental features.”
The UAE, particularly Abu Dhabi, is working hard to establish its environmental credentials through initiatives such as its compulsory green building standards and the Abu Dhabi Future Energy Company’s (Masdar) carbon neutral city, which includes the 100MW Shams 1 solar power project. Coal-fired power generation, even with efficient boilers, would further increase the Gulf’s carbon footprint.
Instead, the region is likely to see a raft of renewable energy projects come to market this year, from wind farms in Egypt and Jordan to solar power projects in the UAE. As a first step towards solar generation, Algeria, Egypt and Morocco are set to complete integrated solar combined-cycle (ISCC) power plants in 2010. ISCC plants work by combining steam generated through a heat exchanger powered by solar thermal energy with steam generated in a heat recovery boiler that collects waste heat from a gas turbine. These combined steam flows drive steam turbines, which in turn power an electricity generator.
One of the biggest challenges is the difference between summer and winter peak [demand]
Bob Bryniak, Golden Sands Management Consulting
But renewable energy projects do not generate sufficient quantities of additional power required to meet rising electricity demand. For this reason, governments throughout the region are turning to nuclear power as a cost-effective and environmental alternative to gas feedstock.
Abu Dhabi has made the most progress in establishing a civilian nuclear energy programme. In late December 2009, the Emirates Nuclear Energy Corporation (Enec) signed a $20.4bn nuclear power contract with a Korean consortium led by Kepco. The joint venture of Kepco, Samsung and Hyundai Engineering & Construction was competing against the French consortium of Areva, GDF Suez and Total, and a US/Japanese team of GE and Hitachi. The deal involves construction of four nuclear reactors, the first of which will begin production in 2017 and is expected to remain operational until 2077. All four plants are scheduled to be running by 2020.
Other states, particularly Jordan, are also making progress in developing nuclear power. These include establishing a nuclear authority, passing nuclear legislation, creating a nuclear energy regulator and investing in training and development. Jordan has awarded a feasibility contract for a 1,000MW plant to be built near the port of Aqaba to Australia’s WorleyParsons. Egypt too has appointed WorleyParsons to conduct a wider ranging study for its first 1,200MW plant. However it has not yet passed the legislation necessary to establish a regulator.
Beyond issues of finance and feedstock, a further problem facing regional utilities when it comes to electricity production is meeting peak demand efficiently. “One of the biggest challenges that the region faces is that the difference between summer and winter peak [demand] is substantial,” says Bryniak.
Developers agree that this variance is a key issue that needs addressing. “In a 24-hour cycle there can be a 150 per cent variance, and with current uncertainty over fuel [availability], utilities should revisit how this is being covered,” says Nomi Ahmad, regional director for Finnish power firm Wartsila. “All tenders are for base-load power, but what is needed is a portfolio of base and peak.” In Jordan, for example, the daily base-load averages around 1,000MW, while the peak is 2,300MW.
From optimising system performance to introducing renewable energy projects and nuclear power, the region is exploring a variety of methods to meet rising electricity consumption. With the improvement in the economic climate, executing new power projects in the Middle East should be much easier in 2010.