NrgEdge Editor

Sharing content and articles for users
Last Updated: December 1, 2016
1 view
Shipping
image

The sulfur content of transportation fuels has been declining for many years as a result of increasingly stringent regulations. In the United States, federal and state regulations limit the amount of sulfur present in motor gasoline, diesel fuel, and heating oil. New international regulations limiting sulfur in fuels for ocean-going vessels, set to take effect in 2020, have further implications for both refiners and vessel operators at a time of high uncertainty in future crude oil prices, which will be a major factor in their operational decisions.


Bunker fuel—the fuel typically used in large ocean-going vessels—is a mixture of petroleum-based oils. Residual oil—the long-chain hydrocarbons remaining after lighter and shorter hydrocarbon fractions such as gasoline and diesel have been separated from crude oil—currently makes up the largest component of bunker fuel. The sulfur content of crude oil tends to be more concentrated in heavier hydrocarbons, with heavier petroleum products such as residual oil having higher sulfur content than lighter ones like gasoline and diesel.


The International Maritime Organization (IMO), the 171-member United Nations agency that sets standards for marine fuels, decided in October to move forward with a plan to reduce the maximum allowable levels of sulfur and other pollutants in marine fuels used on the open seas from 3.5% by weight to 0.5% by weight by 2020. This decision follows several other marine fuel regulations limiting sulfur content, such as the implementation of Emissions Control Area (ECA) requirements in coastal waters and specific sea-lanes in North America and Europe, which limited the maximum sulfur content of fuels to 0.1% by weight starting in July 2015.


The IMO sulfur limits that take effect in 2020 will affect the fuel used in the open seas, the largest portion of the approximately 3.9 million barrels per day of global marine fuel use. These limits will present several challenges for both refiners and shippers.


The first challenge for refiners is to increase the supply of lower sulfur blendstocks to the bunker fuel market. Refiners have several potential paths. One approach is to divert more low-sulfur distillates into the bunker fuel market. Another option is to use low-sulfur intermediate refinery feedstocks in bunker blends.


A second challenge for refiners is deciding what to do with the high-sulfur residual oil that can no longer be blended into bunker fuel. Adding capacity to desulfurize residual oil is one option, but the economics to do so are not currently attractive to refiners. An alternative strategy is to build or expand refinery units that take heavy hydrocarbons and upgrade them into lighter, more valuable products. In either of these cases, refineries would be faced with investments and costs that are acceptable only if there is certainty of future demand from the shipping industry.


Vessel operators also have several choices for compliance with the new IMO sulfur limits. For example, IMO regulations allow for the installation of scrubbers, which remove pollutants from ships' exhaust, allowing them to continue to use higher sulfur fuels. Some ship owners that operate primarily in coastal areas, such as cruise lines and ferries, opted to install scrubbers on their vessels as the new ECA regulations came into force. The possibility of widespread scrubber installations, which would allow ships to continue to use higher sulfur residual oils, could make refiners hesitant about making large investments to build refining units capable of upgrading the residual oils.


Ships also have the option of switching to new lower sulfur blends or to nonpetroleum-based fuels. Some newer ships can use liquefied natural gas (LNG) rather than petroleum-based products. However, the infrastructure to support the use of LNG as a shipping fuel is currently limited in both scale and availability.


Vessel operators and shippers will also likely be faced with higher costs as the sulfur content in marine fuels decreases and as the role of distillate in the bunker fuel market increases. An example of the price difference between fuels can be observed at the Amsterdam-Rotterdam-Antwerp refining and trading hub in Northwest Europe. In 2016, prices for low-sulfur gasoil, a type of distillate, have averaged over $20 per barrel more than high-sulfur fuel oil (residual oil for use as a fuel) to date. Fuel blends used to meet the new IMO regulations are likely to be priced somewhere between these two fuels.

3
0 0

Something interesting to share?
Join NrgEdge and create your own NrgBuzz today

Latest NrgBuzz

Permian’s Pipeline Lifeline

The Permian is in desperate need of pipelines. That much is true. There is so much shale liquids sloshing underneath the Permian formation in Texas and New Mexico, that even though it has already upended global crude market and turned the USA into the world’s largest crude producer, there is still so much of it trapped inland, unable to make the 800km journey to the Gulf Coast that would take them to the big wider world.

The stakes are high. Even though the US is poised to reach some 12 mmb/d of crude oil production next year – more than half of that coming from shale oil formations – it could be producing a lot more. This has already caused the Brent-WTI spread to widen to a constant US$10/b since mid-2018 – when the Permian’s pipeline bottlenecks first became critical – from an average of US$4/b prior to that. It is even more dramatic in the Permian itself, where crude is selling at a US$10-16/b discount to Houston WTI, with trends pointing to the spread going as wide as US$20/b soon. Estimates suggest that a record 3,722 wells were drilled in the Permian this year but never opened because the oil could not be brought to market. This is part of the reason why the US active rig count hasn’t increased as much as would have been expected when crude prices were trending towards US$80/b – there’s no point in drilling if you can’t sell.

Assistance is on the way. Between now and 2020, estimates suggest that some 2.6 mmb/d of pipeline capacity across several projects will come onstream, with an additional 1 mmb/d in the planning stages. Add this to the existing 3.1 mmb/d of takeaway capacity (and 300,000 b/d of local refining) and Permian shale oil output currently dammed away by a wall of fixed capacity could double in size when freed to make it to market.

And more pipelines keep getting announced. In the last two weeks, Jupiter Energy Group announced a 90-day open season seeking binding commitments for a planned 1 mmb/d, 1050km long Jupiter Pipeline – which could connect the Permian to all three of Texas’ deepwater ports, Houston, Corpus Christi and Brownsville. Plains All American is launching its 500,000 b/d Sunrise Pipeline, connecting the Permian to Cushing, Oklahoma. Wolf Midstream has also launched an open season, seeking interest for its 120,000 b/d Red Wolf Crude Connector branch, connecting to its existing terminal and infrastructure in Colorado City.

Current estimates suggest that Permian output numbered around 3.5 mmb/d in October. At maximum capacity, that’s still about 100,000 b/d of shale oil trapped inland. As planned pipelines come online over the next two years, that trickle could turn into a flood. Consider this. Even at the current maxing out of Permian infrastructure, the US is already on the cusp on 12 mmb/d crude production. By 2021, it could go as high as 15 mmb/d – crude prices, permitting, of course.

As recently reported in the WSJ; “For years, the companies behind the U.S. oil-and-gas boom, including Noble Energy Inc. and Whiting Petroleum Corp. have promised shareholders they have thousands of prospective wells they can drill profitably even at $40 a barrel. Some have even said they can generate returns on investment of 30%. But most shale drillers haven’t made much, if any, money at those prices. From 2012 to 2017, the 30 biggest shale producers lost more than $50 billion. Last year, when oil prices averaged about $50 a barrel, the group as a whole was barely in the black, with profits of about $1.7 billion, or roughly 1.3% of revenue, according to FactSet.”

The immense growth experienced in the Permian has consequences for the entire oil supply chain, from refining balances – shale oil is more suitable for lighter ends like gasoline, but the world is heading for a gasoline glut and is more interested in cracking gasoil for the IMO’s strict marine fuels sulphur levels coming up in 2020 – to geopolitics, by diminishing OPEC’s power and particularly Saudi Arabia’s role as a swing producer. For now, the walls keeping a Permian flood in are still standing. In two years, they won’t, with new pipeline infrastructure in place. And so the oil world has two years to prepare for the coming tsunami, but only if crude prices stay on course.

Recent Announced Permian Pipeline Projects

  • September 2018 – EPIC Midstream Holdings – 675,000 b/d, 1125km, 24-30’ diameter, 4Q19 target opening
  • November 2018, Wolf Midstream Partners – 500,000 b/d, 65km, 16’ diameter, 2H2019 target opening
  • November 2018, Jupiter Energy – 1 mmb/d, 1050km, 36’ diameter, 2020 target opening
  • December 2018, Plains All American Pipeline – 575,000 b/d, 830km, 26’ diameter, 3Q19 target opening
December, 04 2018
Your Weekly Update: 3 - 7 December 2018

Market Watch

Headline crude prices for the week beginning 3 December 2018 – Brent: US$61/b; WTI: US$52/b

  • After falling down to fresh lows last week – with WTI prices dipping below US$50/b at one point – crude oil prices improved after the G20 meeting in Buenos Aires, where the US and China agreed to a temporary truce over their trade war
  • While no concrete agreements over energy were announced at the G20 summit, the slightly thawing in trade tensions allowed crude benchmarks to rise slightly, assisted by an announcement by Canadian producers in Alberta that output would be cut by 325,000 b/d beginning January
  • Russia and Saudi Arabia agreed at the G20 summit to extend the OPEC+ deal into 2019, suggesting that a coordinated oil output cut was in the works, also supported prices ahead of OPEC’s meeting in Vienna this week
  • Not present at the OPEC meeting, however, will be Qatar, which quit the oil cartel in a surprise move; the tiny sultanate said it was quitting due to its small oil production, choosing instead to focus on its LNG industry, but the move can be seen as a response to the Saudi-led boycott of Qatar, calling into question Saudi Arabia’s ability to hold the fragile OPEC coalition together
  • Consensus among analysts point to OPEC+ agreeing to remove some 800,000 b/d of crude oil from the market beginning January, aimed at establishing a floor for oil prices at some US$65/b
  • The downward spiral of crude prices has put the brakes on US drilling activity, with 2 new oil rigs offset by the loss of 5 gas rigs last week; analysts are expecting shale explorers to cut spending budgets in 2019 in response to weak prices, raising spectres of the 2015 price slump
  • Crude price outlook: Ahead of the OPEC meeting on December 6, crude should be kept up by expectations of a renewed supply cut, with Brent likely to trade rangebound around US$61-63/b and WTI at US$52-53/b

Headlines of the week

Upstream

  • Buoyed by the prolific nature of the Permian Basin, Shell has announced plans to nearly double its production in the shale patch with AI-powered technology
  • China and the Philippines have set aside sovereignty issues, signing an agreement for joint exploration and development in the South China Sea
  • Facing severe pipeline bottlenecks, Canada’s Alberta province is looking to purchase rail cars to ship more crude oil by train out of the province towards the US, as a temporary measure while new pipeline are proposed and built
  • Shell has completed the sale of Shell E&P Ireland to Nephin Energy Holdings, which includes a 45% in the Corrib gas venture, for US$1.3 billion
  • In Norway, Shell also sold its interests in the Draugen and Gjøa fields for US$526 million to OKEA AS, but retains its interests in the Ormen Lange and Knarr fields, as well as the Troll, Valemon and Kvitebjørn projects
  • Petrobras has sold its stake in 34 onshore production fields to Brazilian firm 3R Petroleum for US$453.1 million, as well as stakes in three shallow-water offshore fields off Rio de Janeiro to Perenco for US$370 million
  • Pemex tripled its estimated reserves in the Ixachi field to 1.3 billion barrels of oil, calling it the ‘most important onshore field in 25 years’ and expecting peak production of 80,000 b/d of condensate and 720 mscf/d of gas by 2022

Downstream

  • Uganda has pushed back the opening of its first oil refinery to 2023, in line with estimates by Total, CNOOC and Tullow Oil, as crude oil production is now only expected to begin in 2021
  • Malaysia will be introducing a B10 biodiesel mandate in December over a phased rollout, with complete implementation expected by February 2018
  • Pertamina expects to begin works on upgrading its Balikpapan refinery in early 2019, aimed to increasing fuel standards to Euro V and upgrading capacity to process sour crude together with its current medium heavies
  • ExxonMobil plans to upgrade its Rotterdam refinery to expand Group II base stock production, following the installation of a new hydrocracker
  • The US EPA has increased its annual blending mandate for advanced biofuels by 15% and kept conventional biofuels blending requirement steady for 2019, while maintaining waivers for selected refineries

Natural Gas/LNG

  • Petronas and Vitol Asia have signed a long-term LNG supply agreement, with Petronas providing LNG from the LNG Canada project in Kitimat, providing up to 800,000 tons per annum for 15 years beginning 2024
  • Eni and Anadarko have been giving a 2023 deadline to submit key development plans for the Area 1 and 4 LNG complex in Mozambique
  • Tullow Oil is backing the attempt by three former Cove Energy executives in the Comoros Islands by taking stakes in Discover Exploration’s blocks, hoping to repeat the trio’s success in discovering the Rovuma block
  • South Korea’s Posco Daewoo has signed a deal with Brunei National Petroleum Company to jointly explore LNG opportunities in Brunei, with specific focus on the development of the Dehwa area operated by Posco Daewoo
  • Rosnedt and the Beijing Gas Group have set up a joint venture focusing on building and operating a network of up to 170 CNG fuel stations in Russia, using LNG as motor fuel
December, 06 2018
Overall Lubricants Market Is Growing In Bangladesh

The engine oil market has grown up around 10 to 12% in the last three years because of various reasons, mostly because of the rise of automobiles. 

According to the Bangladesh Road Transport Authority (BRTA), the number of registered petrol and diesel-powered vehicles is 3,663,189 units.

The number of automotive vehicles has increased by 2.5 times in the last eight years.

The demand for engine oils will rise keeping pace with the increasing automotive vehicles, with an expected 3% yearly growths.

Mostly, for this reason, the annual lubricant consumption raised over 14% growth for the last four years. Now its current demand is around 160 million tonnes.

The overall lubricants demand has increased also for the growth of the power sector, which has created a special market for industrial lubricants oil.

The lubricants oil market size for industries has doubled in the last five years due to the establishment of a number of power plants across the country.

The demand for industrial oil will continue to rise at least for the next 15 years, as the quick rental power plants need a huge quantity of lube oil to run.

The industries account for 30% of the total lubricant consumption; however, it is expected to take over 35% of the overall demand in the next 10 years.

Mobil is the market leader with 27% market share; however, market insiders say that around 70% market shares belong to various brands altogether, which is still undefined.

 It is already flooded with many global and local brands.

December, 01 2018