Fuel oil’s new buyers

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While demand for high-sulfur fuel oil from the shipping industry will be limited going forward, other sectors such as power generation are likely to pick up the slack.

As the shipping industry retreats from fuel oil as its primary energy source, power generation and industrial uses will increasingly dominate the future of this product. This was already clear in 2018, as Saudi Arabian demand was the driving force behind the strength of the European fuel oil complex over the summer, with demand centered on power generation for desalination and to meet increased air-conditioning requirements in the summer months. Saudi Arabia has long sought to reduce crude consumption in its power sector in favor of burning fuel oil, and the specification change in 2020 provides a greater incentive to do so with falling fuel oil prices.

S&P Global Platts Analytics expects an initial bunker demand displacement of about 3 million b/d of fuel oil in 2020, and sees fuel oil displacing 200,000 b/d of crude burn by 2020 as Saudi Arabia ramps up use of the product. Over 10 GW of HSFO capacity is slated to come online by 2020, bringing the country’s fuel oil burn up substantially.

Traditionally, the fuel oil arbitrage from Europe into the Red Sea is a seasonal summer trend from April to October, when Saudi Arabia and other Middle Eastern nations buy fuel oil to power air conditioning. Saudi Arabia drew just under 5 million mt of fuel oil from Europe between May and October 2018, according to S&P Global Platts trade flow software, cFlow. But with the country increasing its desalination capacity by about 3%, buying interest is increasingly expected to emerge even in the winter.

New gas and fuel oil projects in Saudi Arabia are expected to meet increasing power demand growth, particularly in the west and south regions, while gas projects will expand in the central and eastern regions.

The western region is crammed with oil plants, with 52% of these plants burning fuel oil, 35% burning crude and 5% burning gas. There is a push to increase gas use, with the introduction of the 0.5 GW Green Duba plant and the 2.1 GW Rabigh project. However the 3.1 GW fuel oil plant, Yanbu 3, is also in the pipeline to meet increasing desalination requirements. A further push for fuel oil could also come as it replaces crude in steam units, as fuel oil becomes more attractive amid price falls in 2020 given the impending IMO regulations.

As Saudi Arabia continues to burn heavy fuel oil and crude in power plants, emissions concerns seem far from the primary priority. Scrubbers could be used on power stations to help capture some of the sulfur emissions, but they require vast investment capacity and also disposal of the sulfur residue.

“The retrofitting in principle is straightforward and it takes around two to three weeks, but as you make a specialized design for certain plants it can take much longer, six to nine months, and this could also increase if you have a high demand,” said Yousef Alshammari, CEO of UCERGY Analysts.

Looking forward, Saudi Arabia will not remain a source of fuel oil demand indefinitely, as it seeks to boost its renewables mix to decarbonize power production. Considering peak electricity requirements are in the afternoon – between 2:00-3:00 pm in the summer months – the introduction of solar capacity would be a logical means to meet requirements. This includes recently commissioned projects such as the integrated solar systems at Waad Al-Shamal gas plant and the Green Duba Plant.

Moreover, the Saudi energy price reforms that began in 2015 have resulted in a slowdown in electricity demand growth. Prices for natural gas, gasoline, diesel, electricity and water were all raised in 2015, albeit from a very low base. A second round of increases was established in 2018 for gasoline and electricity. In other words, the Saudi government has been phasing out subsidies, in part to address its fiscal deficit. Higher electricity prices have been leading to a change in behavior, especially in the residential sector. Electricity demand growth slowed to 0.7% year on year in 2016 (down from 4.8% growth in 2015), with peak demand down by 2.3% on the year, the first decline in over 20 years. While peak demand may continue to be impacted by these measures, the kingdom is making efforts to attract energy-intensive industries, as part of its reforming agenda, and this will be still supportive of baseload demand growth.

Capacity growth

Fuel oil- red capacity growth is not limited to Saudi Arabia. Bangladesh will be a key outlet for surplus fuel oil in 2020, with emission standards that allow its use in power generation and stronger growth than other parts of the world.

Underpinned by a rapidly growing population and industrial base, Bangladesh has seen power demand growth in the order of 10% over the past few years, but shortages of domestically produced gas and inadequate capacity additions in the prior few years are resulting in persistent load shedding. Extra availability of LNG is helping offset some of the gas shortages and shrinking domestic gas production, but the country is adding fuel oil and diesel- red generation capacity to meet its chronic power shortages.

Installed fuel oil capacity, both public and private, is around 4 GW as of February 2019, with an additional 1 GW expected to be available by 2020. While maximum generation generally falls about one-third short of installed capacity across the Bangladeshi power system as a whole, the country has capacity to increase generation from existing and new oil- red installations, potentially absorbing more than 150,000 b/d in 2020.

What’s interesting is that a number of these fuel oil units are rental power plans or quick-rental power plants – units designed to meet the short-term and emergency requirements of a country, and typically commissioned within four to six months. In Bangladesh, rental periods are normally three to five years (for QRPP) to 15 years (for RPP, depending on the country’s need). In these cases, the Bangladesh Power Generation Board purchases a service, paying agreed tariffs per gigawatt-hour of power. From this perspective, rental plants provide a cash float to the BPDB, as it could not mobilize the huge resources required to set up or build the plants.

Russian fuel exports

These are plants with engines as small as 8-17 MW, which are grouped together to make up 50 to 100 MW plants. Efficiency is fairly high considering that these are open cycle plants, at 40%- 43%. The prices for purchasing power from these rental units were reported to be Taka 9.64/kWh, or about $110/MWh at current exchange rates.

Among the players in this space, Summit Power Limited is worthy of note. It owns and operates over 1.9 GW of fuel oil-and gas-based reciprocating engines in Bangladesh. Interestingly, the fuel oil units are part of a multi- portfolio strategy, with LNG also part of the mix. In fact, in 2017, Summit LNG received a concession from Petrobangla, Bangladesh’s state-owned company, to develop a floating LNG terminal facility comprising a storage and regasification unit on a build, own, operate, transfer basis in Moheskhali, Cox’s Bazar, to supply approximately 500 MMcf/d of natural gas to the national grid. Summit operates a number of gas-based reciprocating engines in the country, but is also developing a 590 MW combined cycle gas turbine expected by January 2021.

Reliability benefits

More generally, fuel oil- or liquid- based reciprocating engines are seen as solutions that offer the benefit of reliability. While relatively low in terms of capital and installation costs, these units have fairly high marginal or variable costs to operate, considering the cost of the fuel and lower efficiency than a CCGT. However, the cost of not supplying a kWh of electricity could be high enough to justify its installation and operation. Economists and regulators use the concept of Value of Lost Load (VoLL) or Value of Lost Adequacy (VoLA) to quantify costs tied to lack of electricity supply, or the loss of socioeconomic activity that takes place when electricity is not provided to consumers. In a recent study for the EU Agency for the Cooperation of Energy Regulators, the cost of not supplying electricity is quantified in ranges of €1,500-22,940/MWh (roughly $1,700 -26,300/MWh) for the domestic sector in Europe, while for the industrial sector that range tends to be wider.

Reliability concerns tied to extreme weather events have driven the installation of these units in other countries. In addition, liquid fuels such as fuel oil represent a more secure source, especially as gas could be unavailable in some regions or scarce at times – for example, during extreme cold weather events. Outside of Saudi Arabia, where fuel oil plants are being built in tandem with large refining complexes, or to substitute crude plants for baseload generation, a vast majority of HSFO plants are essentially being built for such reliability or short-term emergency needs. According to the S&P Global Platts World Electric Power Plants Database, there are about 7 GW of fuel oil-based units being built or at a planning stage across the world outside Saudi Arabia. What’s interesting is that the average size of these projects is 44 MW, with almost 100 projects below the 20 MW threshold.

Islands also represent excellent sites for small fuel oil-based units, with 1.2 GW of fuel oil-based units in construction or planned on islands, according to the S&P Global Platts World Electric Power Plants Database. This is about 17% of total fuel oil units being built outside of Saudi Arabia. Among these islands, the largest plants are in Cuba (200 MW), Sri Lanka (170 MW) and Madagascar (170 MW).

In this context, it is interesting to note that 3 GW of floating power plants have been built and operated by the Karadeniz Energy Group, through their subsidiary Powership and fueled by HFSO, diesel or natural gas. A large portion of this floating power capacity is currently in Indonesia; six floating plants for a total of almost 1 GW.

Lebanon hosts two of these floating power plants – for a total of 370 MW – while a third one was also used to mitigate the country’s electricity shortages during the summer.

Traditionally a devoted user of fuel oil for power generation, Lebanon is now looking towards natural gas to fuel its future. The government had a tender in December to build two FSRUs running on LNG. Fuel oil will begin to be phased out from the Middle East nation, and one local power generation consultant expects the trend away from fuel oil to become global as the World Bank become more stringent on emissions.

While scrubber installations on power stations are an option, the significant expense may not be justified if new emissions standards are introduced. Additionally, in countries such as Lebanon, there is a lack of facilities to store and dispose of the high sulfur residue, the consultant added.

The supply and demand imbalances caused by the IMO’s 0.5% sulfur cap could be subject to the law of unintended consequences. While the 2020 sulfur cap will endeavor to protect the marine environment and human health in an act of stewardship, the excess cheap HSFO sidelined from the bunker industry could prove attractive to nations trying to save on costs for power generation. “Cost is the main driver for energy options. In the absence of stringent environmental regulations, cheap and polluting fuels will certainly find a market, regardless of their environmental impact,” UCERGY Analysts’ Alshammari said.

While stringent sulfur or air-quality regulations have translated into strict limits to operation of oil units in a number of countries, fuel oil has also been typically priced at higher levels relative to coal or other alternatives. As such, even if scrubbers are effective at removing sulfur in oil units, the operational fuel oil capacity globally has not been subject to environmental upgrades. In fact, the the S&P Global Platts World Electric Power Plants Database shows that out of the 132 GW of units identified as burning HSFO and currently operationally globally, only about 11 GW are known for having flue-gas desulfurization or scrubbers installed, with the largest regions being Asia and the Middle East.

Analysts believe the power sector could end up playing a pivotal role in propping up the fuel oil market, even though environmental policies in some countries might prevent this from becoming a major trend.

Fuel oil use in power generation is restricted by regulations on sulfur and carbon dioxide emissions. For instance, Japan traditionally used low sulfur crude and low sulfur fuel oil for power generation, but has changed track more recently. This includes limiting the sulfur content of fuel burned in power plants to 0.5%. It is also increasing renewables and nuclear unit use, reducing fossil fuel needs. South Korea has similarly stepped towards a cleaner future, despite having 4 GW of oil-fired capacity on government air standard regulations, a focus on LNG imports and flue-gas desulfurization capacity.

China has also had a renewables drive, taking measures to reduce urban air pollution and has significant spare generating capacity from less polluting plants. Growing Chinese LNG demand is coming from industry, city gas, and heating requirements rather than the power generation sector.

Additionally, Pakistan was once a major demand center for fuel oil, and burned 158,000 b/d of fuel oil in 2016, according to S&P Global Platts Analytics. Now the country’s increasing use of LNG for power generation at the expense of oil has resulted in Pakistan State Oil cutting fuel oil imports drastically last year, even during the peak summer demand season of May-September. Pakistan’s fuel oil demand plummeted by 120,000 b/d from August 2017 to the same month of 2018, reflecting the country’s switch to natural gas, the October monthly oil report from the International Energy Agency said.

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