It’s been a long time coming, but 2018 will be the year Australia becomes a LNG export powerhouse. After years of delays and billions of dollars wasted from postponements, the final two projects of the initial six LNG projects, tapping into giant natural gas basins in the north and northwest waters off Australia are finally ready. Shell’s Prelude FLNG project, which was once planned to be the first FLNG project in the world until Petronas FLNG Satu and Golar LNG beat them to it – is now ‘materially ready’ to begin production, while Inpex’s Ichthys project is scheduled for a Q218 operational start-up after years of delays. The struggles with meeting timelines isn’t confined to Shell and Inpex; with the exception of Darwin LNG, all of the major Australia north-western projects have struggled with workforce issues and service operations. The slump in crude & LNG prices also thwarted the once best laid plans.
But finally it is done. Australia’s six major LNG projects have added some 41 mtpa of LNG to a global demand base that is still growing strongly. Between now and 2035, natural gas demand is expected to grow at an average of 2% per year; twice the rate of total global energy demand. Demand for LNG is set to increase at an average of 4% per year. This year China overtakes South Korea’s massive appetite for the super-cooled and clean(er) fuel. Japan still holds its number one importer for now. Asian demand grew by more than 17 million tonnes, beating industry predictions going into the year. That is nearly as much as the total volume that Indonesia, the world’s 5th largest exporter, produced in 2017. However there are challenges that come with high LNG consumption growth. Namely, infrastructure. In China, where demand for LNG is expected to double within the next six years, LNG tanks were full to the brim last winter, and it could take no more, resulting in the tanks closed for a few weeks. Other hungry markets like Pakistan and Bangladesh and Vietnam, lack import capacity, which takes time to build hence the idea of deploying floating storage and regasication units (FRSUs) there.
There are also worries, legitimate ones, that increased gas production from the rest of the world, including Russian piped gas and LNG, as well as America entering the fray with recent LNG exports to Europe and China, would spoil the party for the Australians. But it seems that the real victim is Canada. While Australia managed to enter the market in the nick of time – or so it seems – the promised ‘tsunami’ of LNG that would threaten markets in 2022/23, is less of a threat now. And that’s entirely because projects in Canada’s Pacific Northwest – which lagged behind by Australia’s by only a decade at most – did not make financial sense. Particularly given that environmental and indigenous population concerns are exponentially tougher to overcome in British Columbia. Petronas and Nexen have cancelled their projects, and are seemingly rallying behind Chevron’s Kitimat, which itself it facing problems both politically and economically. Meanwhile, American Gulf Coast LNG is nimbly developing along.
While Australia’s LNG appears to have made the grade, will Canada’s projects see the light of day? If you have read Shell’s LNG 2018 outlook report, it may appear so. “Following the wave of investment from 2011 to 2015, final investment decisions (FIDs) on LNG projects have nearly stopped. As LNG projects generally take more than four years to start production, new supply will not be ready until well into the next decade. FIDs on new LNG supply projects are required soon to avoid a supply shortage in the 2020’s.”
Up-coming courses on Gas and LNG in the region
LNG Fundamentals - http://bit.ly/2DqpkXM
Small Scale LNG Operations - http://bit.ly/2IlmXsZ
LNG Bunkering - http://bit.ly/2p91fzw
LNG Terminal Operations - http://bit.ly/2paJM9Q
LNG Markets, Pricing and Risk Management - http://bit.ly/2pf38f5
Gas & LNG Contract Negotiations - http://bit.ly/2DpJm4I
Gas Processing - http://bit.ly/2IowrDz
Advanced LNG Vessel Transfer Ship to Ship (STS) - http://bit.ly/2HPDTXd
Integrated Methods For Offshore LNG Transfer - http://bit.ly/2FUTZOJ
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
Less than two weeks ago, the VLCC Navarin arrived at Tanjung Pengerang, at the southern end of Peninsular Malaysia. It was carrying two million barrels of crude oil, split equally between Saudi Arab Medium and Iraqi Basra Light grades.
The RAPID refinery in Johor. An equal joint partnership between Malaysia’s Petronas and Saudi Aramco whose 300 kb/d mega refinery is nearing completion. Once questioned for its economic viability, RAPID is now scheduled to start up in early 2019, entering a market that is still booming and in demand of the higher quality, Euro IV and Euro V level fuels RAPID will produce.
Beyond fuel products, RAPID will also have massive petrochemical capacity. Meant to come on online at a later date, RAPID will have a collective capacity of some 7.7 million tons per annum of differentiated and specialty chemicals, including 3 mtpa of propylene. To be completed in stages, Petronas nonetheless projects that it will add some 3.3 million tons of petrochemicals to the Asia market by the end of next year. That’s blockbuster numbers, and it will elevate Petronas’ stature in downstream, bringing more international appeal to a refining network previously focused mainly on Malaysia. For its partner Saudi Aramco, RAPID is part of a multi-pronged strategy of investing mega refineries in key parts of the world, to diversify its business and ensure demand for its crude flows as it edges towards an IPO.
RAPID won’t be alone. Vietnam’s second refinery – the 200 kb/d Nghi Son – has finally started up this year after multiple delays. And in the same timeframe as RAPID, the Zhejiang refinery by Rongsheng Petro Chemical and the Dalian refinery by Hengli Petrochemical in China are both due to start up. At 400 kb/d each, that could add 1.1 mmb/d of new refining capacity in Asia within 1H19. And there’s more coming. Hengli’s Pulau Muara Besar project in Brunei is also aiming for a 2019 start, potentially adding another 175 kb/d of capacity. And just like RAPID, each of these new or recent projects has substantial petrochemical capacity planned.
That’s okay for now, since demand remains strong. But the danger is that this could all unravel. With American sanctions on Iran due to kick in November, even existing refineries are fleeing from contributing to Tehran in favour of other crude grades. The new refineries will be entering a tight market that could become even tighter. RAPID can rely on Saudi Arabia and Nghi Son can depend on Kuwait, both the Chinese projects are having to scramble to find alternate supplies for their designed diet of heavy sour crude. This race to find supplies has already sent Brent prices to four-year highs, and most in the industry are already predicting that crude oil prices will rise to US$100/b by the year’s end. At prices like this, demand destruction begins and the current massive growth – fuelled by cheap oil prices – could come to an end. The market can rapidly change again, and by the end of this decade, Asia could be swirling with far more oil products that it can handle.
Upcoming and recent Asia refineries:
Headline crude prices for the week beginning 8 October 2018 – Brent: US$84/b; WTI: US$74/b
Headlines of the week
Source: U.S. Energy Information Administration, Monthly Crude Oil and Natural Gas Production
As domestic production continues to increase, the average density of crude oil produced in the United States continues to become lighter. The average API gravity—a measure of a crude oil’s density where higher numbers mean lower density—of U.S. crude oil increased in 2017 and through the first six months of 2018. Crude oil production with an API gravity greater than 40 degrees grew by 310,000 barrels per day (b/d) to more than 4.6 million b/d in 2017. This increase represents 53% of total Lower 48 production in 2017, an increase from 50% in 2015, the earliest year for which EIA has oil production data by API gravity.
API gravity is measured as the inverse of the density of a petroleum liquid relative to water. The higher the API gravity, the lower the density of the petroleum liquid, meaning lighter oils have higher API gravities. The increase in light crude oil production is the result of the growth in crude oil production from tight formations enabled by improvements in horizontal drilling and hydraulic fracturing.
Along with sulfur content, API gravity determines the type of processing needed to refine crude oil into fuel and other petroleum products, all of which factor into refineries’ profits. Overall U.S. refining capacity is geared toward a diverse range of crude oil inputs, so it can be uneconomic to run some refineries solely on light crude oil. Conversely, it is impossible to run some refineries on heavy crude oil without producing significant quantities of low-valued heavy products such as residual fuel.
Source: U.S. Energy Information Administration, Monthly Crude Oil and Natural Gas Production
API gravity can differ greatly by production area. For example, oil produced in Texas—the largest crude oil-producing state—has a relatively broad distribution of API gravities with most production ranging from 30 to 50 degrees API. However, crude oil with API gravity of 40 to 50 degrees accounted for the largest share of Texas production, at 55%, in 2017. This category was also the fastest growing, reaching 1.9 million b/d, driven by increasing production in the tight oil plays of the Permian and Eagle Ford.
Oil produced in North Dakota’s Bakken formation also tends to be less dense and lighter. About 90% of North Dakota’s 2017 crude oil production had an API gravity of 40 to 50 degrees. The oil coming from the Federal Gulf of Mexico (GOM) tends to be more dense and heavier. More than 34% of the crude oil produced in the GOM in 2017 had an API gravity of lower than 30 degrees and 65% had an API gravity of 30 to 40 degrees.
In contrast to the increasing production of light crude oil in the United States, imported crude oil continues to be heavier. In 2017, 7.6 million b/d (96%) of imported crude oil had an API gravity of 40 or below, compared with 4.2 million b/d (48%) of domestic production.
EIA collects API gravity production data by state in the monthly crude oil and natural gas production report as well as crude oil quality by company level imports to better inform analysis of refinery inputs and utilization, crude oil trade, and regional crude oil pricing. API gravity is also projected to continue changing: EIA’s Annual Energy Outlook 2018 Reference case projects that U.S. oil production from tight formations will continue to increase in the coming decades.