A tripling of LNG output likely to hit the shipping market

A predicted tripling of sanctions for global LNG projects in 2019 threatens to disrupt future shipping logistics as demand for the gas enters a more volatile phase because of a rapid increase in supply.

This is the result of a likely record year for final investment decisions (FIDs) that will ultimately deliver more than 60M tonnes of LNG per year (mta), nearly three times the 21 mta sanctioned in 2018, as the research director for Wood Mackenzie Giles Farrer forecasts. Inevitably, increased availability of LNG will influence where tankers deliver their loads.

But Wood Mackenzie also predicts shorter-term volatility in the vagaries of the weather that could affect shipping movements – “a mild end to [the 2019] winter could send more LNG into Europe and drive prices down further,” he said.

The energy consultant’s predictions come at a time of concern over the availability of LNG tankers to handle the huge extra output, particularly in the spot market because most of the fleet are locked into exclusive long-term charters. In a mid-2018 study, the International Energy Agency highlighted a possible shortfall in vessels as a threat to the security of supply, particularly in more remote regions.

The dearth of available LNG carriers is reflected in rocketing spot charter rates. In November, they shot to US$190,000 a day, five times higher than in early May.

Overall though, it appears the tanker fleet will have to adjust to changes in demand in the medium-term future. “Asian LNG demand growth will not keep pace with LNG supply and Europe – northwest Europe in particular – will have to absorb the surplus, especially during the summer,” he predicted in a release this week. “But Europe needs additional imports and flexibility, given its increased reliance on maxed-out Russian and Norwegian imports.”

It is therefore likely, he added, “there would be more LNG imports than required. And that in turn would provide competition to pipe imports and put pressure on prices,” he said. However Mr Farrer does not see the level of oversupply in 2019 that others fear.

A record number of LNG projects, as measured by volume, are due to get the green light. Wood Mackenzie sees the frontrunners in the race to hit FID in 2019 as the giant US$27Bn Arctic LNG-2 project in Russia, at least one project in Mozambique and three in America. Of the latter, Wood Mackenzie identifies three major operations as top picks – Golden Pass, Calcasieu Pass and Sabine Pass Train 6.

But that is not all. There are other projects in the pipeline in America as well as in Qatar, Papua New Guinea, Australia and Nigeria, all aiming for FID in 2019.

Wood Mackenzie sees other global influences that would inevitably determine the course of the growing LNG shipping network. “A recession would bring gas/LNG demand and oil prices down, delay FIDs and push the global LNG market back a few years,” said Mr Farrer. “But there could be a worse scenario for the gas market: a major economic downturn happening in 2020 or 2021, just after 60-100 mta of LNG has taken FID. That would wipe out our forecast price recovery post-2020 and make our forecast that prices soften a little around 2025 look a lot worse.”

Chinese demand is also less certain than it was in 2018, particularly if Beijing rethinks its headlong switch from coal to gas. In the last two years demand for LNG hovered between 40-45% growth, but that could fall to about 20%. However, as Wood Mackenzie pointed out, even if that happened China would remain by far the largest customer for LNG in the global market.

12.01.2019 kl 14:24 1047

Growth in the global liquefied natural gas (LNG) market last year was “driven by Asia and that Asian component has been driven by China,” Anatol Feygin, executive vice president and chief commercial officer of Cheniere Energy explained at the Atlantic Council’s 2019 Global Energy Forum in Abu Dhabi on January 12.

The 30 million ton increase in the global LNG market in 2018 was almost exclusively due to growth in the Asian market, Feygin explained, fueled by a desire among China, Japan, South Korea, and others to “transition towards cleaner fuels.” While demand is up over all of Asia, “China is going to be for the foreseeable future a very large driver of natural gas demand and LNG as well,” Feygin said.

Wang Zhongying, the director general of the Chinese National Development and Reform Commission’s Energy Research Institute, said that he believes his country is in the first phase of a comprehensive energy transition, during which time cleaner sources of energy—such as natural gas—will be vital. “Our fossil fuels still count for almost 87 percent of total primary energies,” Wang explained. “Our priority is to reduce coal consumption. So during the first phase if we can use more and more gas, that will help us.”

The need for cleaner forms of fuel is not just limited to China, however, as Jennifer Gnana, an energy reporter for The National and the panel moderator explained. “Asian energy demand has been forecast to grow by 37 percent by 2025 and as a result of this growth it is expected to see an increase in energy imports by around 53 percent,” she said. At the same time, “due to the volatility in the price of oil as well as the pollution in metros seen in China and India there has been a growing transition of these economies to a more decarbonized energy model.”

“Three years ago, everyone knew for a fact that the world was going to be oversupplied with LNG,” recalled David Hobbs, a senior fellow in the Atlantic Council’s Global Energy Center. “The basis of that was a vast expansion of supply, but that the two potentially large importers, China and India, would not be able to pay the price necessary for LNG to come into their markets in a big way. What changed was the realization that social stability and public health was being affected by air quality and people were prepared to pay that price.”

In Japan, the Fukushima accident in 2011 has spurred action to replace nuclear power with other forms of fuel such as LNG, Yongsung Cho, president of the Korea Energy Economics Institute, said. South Korea’s attempted transition away from coal-fired power plants has spurred similar demand, Cho said. Despite a shared concern in procuring cheap LNG, Cho lamented, China, South Korea, and Japan have yet to undertake concerted cooperation in the energy market.

Asia’s growing appetite for LNG is also the subject of a new report by Atlantic Council senior fellow Jean-Francois Seznec, “Meeting Asian LNG Demand.” In the paper, Seznec explores the impact of LNG demand on the geopolitical relationships between LNG producers around the world and the new customers in Asia.

There is no guarantee, however, that Asia’s love affair with LNG will last, the panelists warned. One threat mentioned was the United States’ continued trade war with China, which saw Beijing slap a 10 percent tariff on imported US LNG in September. “It would be unfair for me to say that I am not against these tariffs that have been in place. I think it is additional friction in the market,” Feygin said. He trusts, however, that the global LNG market “is large enough and liquid enough to appropriately distribute the molecules to their most economically efficient destination.” Hobbs agreed saying he suspects that “the quantities of gas going into Asia will be totally unaffected by tariffs…but exactly whose gas goes where may be up for discussion.” While he does see the trade war as “a big impediment,” Feygin said, he “would prefer it wasn’t there.”

A considerable rise in the price of LNG could also cause a significant dent in Asian demand for LNG. “If the gas price increases too much,” Wang said, “I think we will move to another energy source.” According to Cho, South Korea is looking forward in the long term to a potential ground pipeline from Russia, should relations between North and South Korea dramatically improve.

While China and others have shouldered LNG’s higher prices in order to ensure progress on lessening pollution, it will always be a cost benefit analysis, Hobbs argued. “Governments in Asia put welfare generation—in other words economic growth and development—ahead of long-term decarbonization, and they always will.”


Det er mange utfordringer, men alt tyder jo på at forbruket av gass vil øke og at behovet etter transport av LNG vil øke.
Nesten merkelig at det ikke er mere bevegelse i selskaper som Flex som har mange skip i bestilling.

China Pushes LNG Imports to the Limit

China is importing record volumes of liquefied natural gas (LNG) to meet its air quality targets and may have no alternative for the next several years, experts say.

In November, China's LNG imports soared 48.5 percent from a year earlier to 5.99 million metric tons, according to customs figures. In the 11-month period, imports of 47.52 million tons climbed 43.6 percent from a year before, the official Xinhua news agency said.

Total natural gas imports, including both pipeline gas and LNG, rose 31.9 percent to a record of 90.39 million tons last year, the General Administration of Customs said Monday.

Last year marked the second in a row of LNG growth rates of over 40 percent as the government presses ahead with its wintertime fuel-switching policy to reduce heating with high- polluting coal.

Despite higher costs and infrastructure problems, the government has shown determination to pursue the gas policy as the gap between domestic production and consumption grows.

In November, China's gas output jumped 10.1 percent from a year earlier, but the daily consumption rate also rose to a new record on Nov. 21, Reuters reported, citing the National Development and Reform Commission (NDRC).

A detailed study released last month by the Oxford Institute for Energy Studies suggests that China faces a critical period between now and 2020 with implications for the international LNG market, depending on how far the government pushes its fuel-switching campaign.

Total natural gas consumption in 2020 will range between 300 billion and 400 billion cubic meters (10.6 trillion and 14.1 trillion cubic feet), based on minimum and maximum estimates of coal-to-gas switching, said the study by senior researchers and analysts at Osaka Gas Co., Ltd. of Japan.

Central Asian pipeline network

Domestic gas production is likely to contribute 180 billion to 200 billion cubic meters (bcm), or anywhere from 45 to 67 percent of consumption. In the first 11 months of 2018, China's gas output inched up 6.6 percent from a year earlier to 143.8 bcm, Reuters said, citing National Bureau of Statistics (NBS) data.

China can fill some of the gap with imports of pipeline gas, but capacity and supplies will be limited, the study said.

The country's major Central Asian pipeline network from Turkmenistan through Uzbekistan and Kazakhstan is nearing its rated capacity of 55 bcm per year. Efforts are planned to boost the volume to 65 bcm with new compressor stations, but progress on building a fourth strand of the system through Tajikistan appears stalled.

Last year, the Central Asian system increased supplies by 21 percent to 46.9 bcm, according to state-owned Turkmengaz, as reported by Azerbaijan's Trend News Agency.

Another import pipeline through Myanmar is expected to deliver only modest volumes to China in 2020, estimated at 4 bcm, despite its 10-bcm capacity.

And Russia's mammoth Power of Siberia gas pipeline project, scheduled to open next December, will supply China with only 6 bcm in 2020, the analysts said. By then, the total of pipeline gas available to China will reach only 55- 65 bcm, they said.

The rest of China's demand will have to be filled by LNG imports, although the conclusions are subject to a host of variables.

Last year, China overtook South Korea to become the world's second-largest LNG importer, surpassed only by Japan.

According to the study, China had 19 receiving terminals for the tanker-borne fuel with an annual capacity of about 59.6 million tons as of last August. The volume is the equivalent of about 81 bcm.

By 2020, new terminals and other infrastructure could raise LNG import capacity to as much as 70 million tons, or about 95 bcm.

‘Virtually impossible to meet projected demand’

Although some of China's terminals have already operated at more than 100 percent of their rated capacity, the study concludes that "it will be virtually impossible to meet projected demand" if China sticks to its maximum target for switching from coal to gas.

Capacity constraints will also keep China from meeting its 2020 target for raising the natural gas share of its primary energy supply to 10 percent, the study said. Gas is believed to account for about 6 percent of the country's energy mix now.

The authors also see implications for LNG demand beyond 2020 if Russia's plans for larger volumes of pipeline gas are delayed.

The study said that "LNG demand will depend above all on steady growth in natural gas imports from Russia from 2020 onward. If imports from Russia grow steadily, this makes it more likely that LNG imports will slow from 2020. Conversely, if natural gas imports from Russia do not, for some reason, grow as planned, dependence on LNG will increase further."

The conclusions suggest that China may have to pursue more moderate targets or build even more LNG infrastructure to avoid excessive reliance on Russian supplies.

Mikkal Herberg, energy security research director for the Seattle-based National Bureau of Asian Research, said the report highlights both pluses and minuses for China as gas demand rises at astronomical rates.

On the plus side, the finding that eastern LNG import terminals were able to operate at over 100 percent of rated capacity suggests there may be elasticity in the system, said Herberg.

On the downside, the average 82-percent utilization rate of all terminals as of mid 2018 is a sign that the system will be running "pretty close to flat out" with the larger volumes expected in 2020, he said.

Although the international LNG market is expected to be well supplied over the next two years, any glitch in China's system could lead to sudden shortages.

"It's still a pretty rickety LNG and gas supply logistics system bumping up against stunning increases in LNG use," Herberg said by email.

"Lots can go wrong, especially if there's a very cold winter in 2019 or 2020," he said. "The system will be running so tight that things will get very difficult, and serious regional supply shortages would inevitably occur."

'Industry and market indigestion’

Vessel traffic at China's receiving terminals is likely to become intense if current growth rates continue.

The study noted that in December 2017, the NDRC issued emergency measures in response to gas shortages, ordering 39 LNG cargoes in addition to the 248 that had already been planned for the winter season.

The potential for disruption came into focus over the weekend after a liquefied petroleum gas (LPG) carrier leaked gas into the water near Dongying port in east China's Shandong province, Xinhua reported.

The incident on Saturday due to a valve malfunction on a South Korean-registered tanker is being monitored for environmental impacts, Xinhua and China Global Television Network (CGTN) said.

Ships have been warned to avoid the area. Xinhua reported Monday that the leak had been stopped.

Other reports have raised questions about the availability of LNG carriers (LNGCs) to respond to high demand growth and winter emergencies.

According to the latest count by the Paris-based International Energy Agency (IEA), the world fleet of LNGCs consisted of only 467 tankers in mid-2018.

The low rate of orders for new vessels suggests that China's demand growth could exceed fleet capacity.

"Considering that LNGC construction takes between two and three years, fleet capacity is expected to remain almost flat in 2020 (and possibly 2022) unless new orders are placed in the coming months," the IEA said in its October report.

Some of those concerns may have been eased by a rush of new orders late in the year, a report last month by lngworldshipping.com said.

But the lengthening list of potential problems suggests that China has entered a high-risk period as it strives to meet its air quality and energy goals.

"Any country trying to raise LNG imports at the pace and scale of China over the past few years would experience monumental 'industry and market indigestion,'" said Herberg.

China's soaring demand for LNG has already played havoc with shipping costs, affecting the entire Asian market.

Spot charter rates for LNG carriers in November rose fivefold since May to U.S. $190,000 (1.3 million yuan) per day, Japan's Nikkei Asian review reported on Jan. 2.

"We did not expect that we would run short of vessels so quickly," an unidentified official at a major Japanese shipping company was quoted as saying.


LNG vessel spot rates in Pacific below $80,000/d for first time since late Aug

The spot charter rate for LNG spot vessels has fallen below $80,000/day in the Pacific for the first time since late August, with S&P Global Platts assessing Pacific rates at $75,000/day.

The ballast rate was assessed at 100% in the Pacific, meaning shipowners were being fully compensated for the return leg of the journey.
The low came after the market hit a record high of $190,000/day during the fourth quarter on a lack of spot tonnage availability in Asia.

Around 5-10 vessels were said by sources to be available for prompt loading, including offers from portfolio players such as BP, Cheniere and Shell.

Cheniere was said to have sublet the Lena River at around $68,000/day for a spot reload from Kochi, India. Unipec was said to have fixed a Shell or Coolpool vessel in the mid-$70,000s to $80,000/day for an early APLNG load.

Prior to that, ExxonMobil was said to have fixed the British Partner or British Achiever for a February 6-10 Gorgon or PNG load, at a hire rate around the $90,000s/day.

Shipping typically accounts for 5%-20% of the delivered price ex-ship of LNG, meaning big moves in rates can have a significant effect on the final price of delivered gas.


Natural Gas Weekly Update

In the News:
U.S. LNG exports increase this winter, as two new trains are placed in service

U.S. liquefied natural gas (LNG) exports set two consecutive monthly records in November and December 2018, with 32 and 36 exported cargoes, respectively. Two new liquefaction trains—Sabine Pass Train 5 and Corpus Christi Train 1—began LNG production in late November. EIA estimates that U.S. LNG exports averaged 3.6 billion cubic feet per day (Bcf/d) in November and 3.9 Bcf/d in December, based on the vessel shipping data provided by Bloomberg Finance, L.P.

The United States began exporting LNG from the Lower 48 states in February 2016, when the Sabine Pass liquefaction terminal in Louisiana shipped its first cargo. Since then, Sabine Pass expanded from one to five operating liquefaction trains, Cove Point LNG export facility began operation in Maryland, and Corpus Christi Train 1 began LNG production several months ahead of schedule and shipped its first cargo in December. U.S. LNG exports are poised to increase further as more export facilities come online in 2019–21.

Existing U.S. LNG nominal baseload liquefaction capacity is estimated at 4.25 Bcf/d and peak capacity at 4.87 Bcf/d across seven trains at three liquefaction terminals. Once the remaining facilities under construction—Elba Island, Cameron, and Freeport—and the remaining two trains at Corpus Christi are placed in service, EIA estimates that U.S. nominal baseload liquefaction capacity will stand at 9.6 Bcf/d (72.3 million metric tons per annum (mtpa)) and peak capacity at 10.7 Bcf/d (80.9 mtpa). Once all trains are fully ramped up post-2020, U.S. liquefaction facilities will likely operate at peak nominal capacities during periods of peak demand, particularly in winter and summer months.

EIA estimates that Sabine Pass facility has been running above 100% of its nominal baseload liquefaction capacity in the winter months and near 100% of its baseload capacity in the summer months once the new trains at the facility have been fully ramped up. Utilization of the facility in the winter 2017–18 is estimated at 107% of the nominal baseload and 92% of peak capacity; in the summer 2018—at 97% and 83%, respectively. Annual 2018 utilization at Sabine Pass is estimated at 106% of the baseload and 91% of peak capacity. Cove Point terminal has also run above 90% of its baseload capacity in November–December 2018, with an overall utilization of 67% of baseload and 62% of peak capacity since the facility started operation in March 2018.

Because commissioning of the new facilities is done gradually over a period of several months, EIA forecasts U.S. LNG exports to increase gradually in 2019 and average 5.1 Bcf/d on an annual basis, up from 3.0 Bcf/d annual average in 2018. In 2020, however, as the new trains ramp up LNG production, U.S. LNG exports are projected to increase and average 6.8 Bcf/d annually, with higher exports in the winter and summer seasons and lower exports in the spring and fall months.

The latest information on the status of U.S. liquefaction facilities, including expected online dates and capacities, is available in EIA's database of U.S. LNG export facilities.

(For the Week Ending Wednesday, January 16, 2019)

Natural gas spot prices rose at most locations this report week (Wednesday, January 9 to Wednesday, January 16). Henry Hub spot prices rose from $2.91 per million British thermal units (MMBtu) last Wednesday to $3.61/MMBtu yesterday.
At the Nymex, the price of the February 2019 contract increased 40¢, from $2.984/MMBtu last Wednesday to $3.384/MMBtu yesterday. The price of the 12-month strip averaging February 2019 through January 2020 futures contracts climbed 12¢/MMBtu to $2.965/MMBtu.
Net withdrawals from working gas totaled 81 billion cubic feet (Bcf) for the week ending January 11. Working natural gas stocks are 2,533 Bcf, which is 3% lower than the year-ago level and 11% lower than the five-year (2014–18) average for this week.
The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 26¢/MMBtu, averaging $6.46/MMBtu for the week ending January 16. The price of natural gasoline, ethane, propane, butane, and isobutane all rose, by 5%, 1%, 7%, 3%, and 1%, respectively.
According to Baker Hughes, for the week ending Tuesday, January 8, the natural gas rig count increased by 4 to 202. The number of oil-directed rigs fell by 4 to 873. The total rig count remains unchanged at 1,075.


Prices rise across most of the Lower 48 states. This report week (Wednesday, January 9 to Wednesday, January 16), Henry Hub spot prices rose 70¢ from $2.91/MMBtu last Wednesday to their weekly high of $3.61/MMBtu yesterday. At the Chicago Citygate, prices increased 82¢ from $2.70/MMBtu last Wednesday to $3.52/MMBtu yesterday. Temperatures remained cold for most of the report week, and the return of winter weather, especially on the East Coast, put upward pressure on prices.

Northeast prices mostly rise. Below-freezing temperatures across most of the Northeast led to higher prices. At the Algonquin Citygate, which serves Boston-area consumers, prices went up $4.78 from $6.60/MMBtu last Wednesday to their weekly high of $11.38/MMBtu yesterday.

Prices at the Transcontinental Pipeline Zone 6 trading point in New York City rose by $2.13 from $3.12/MMBtu last Tuesday to $5.25/MMBtu last Wednesday, in anticipation of colder temperatures. Since then, prices gradually dropped to $4.04/MMBtu yesterday.

Tennessee Zone 4 Marcellus spot prices increased 72¢ from $2.71/MMBtu last Wednesday to $3.43/MMBtu yesterday. Prices at Dominion South in southwest Pennsylvania rose 77¢ from $2.65/MMBtu last Wednesday to $4.42/MMBtu yesterday.

Prices rise in California. Prices at PG&E Citygate in Northern California rose $1.20 from $3.42/MMBtu last Wednesday to $4.62/MMBtu yesterday. Prices at SoCal Citygate increased 71¢ from $4.66/MMBtu last Wednesday to $5.37/MMBtu yesterday. Higher prices were largely driven by cooler temperatures during the report week, particularly in Southern California, leading to withdrawals from storage.

Discount at Permian Basin trading hub persists. Prices at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $2.06/MMBtu last Wednesday, 85¢/MMBtu lower than Henry Hub prices. Yesterday, prices at the Waha Hub averaged $2.29/MMBtu, $1.32/MMBtu lower than Henry Hub prices.

Supply rises as dry natural gas production continues to grow. According to data from PointLogic Energy, the average total supply of natural gas rose by 1% to 94.4 Bcf/d compared with the previous report week. Dry natural gas production grew by 1% to 88 Bcf/d compared with the previous report week. Average net imports from Canada increased by 5% from last week as U.S. imports from Canada increased while U.S. exports to Canada declined.

Demand rises amid cooler temperatures. Total U.S. consumption of natural gas rose by 18% compared with the previous report week, according to data from PointLogic Energy, averaging 97.2 Bcf/d. Natural gas consumed for power generation rose 14%. Industrial sector consumption increased 5% week over week. In the residential and commercial sectors, consumption increased 30%, averaging 46.9 Bcf/d during the report week as winter weather swept through most of the Lower 48 states. Natural gas exports to Mexico declined 1% week over week, averaging 4.7 Bcf/d for the report week.

U.S. LNG exports decrease week over week. Eight LNG vessels (six from Sabine Pass, one from Cove Point, and one from Corpus Christi) with a combined LNG-carrying capacity of 28.4 Bcf departed the United States between January 10 and January 16, and two vessels were loading on Wednesday―one at Sabine Pass and one at Cove Point—according to shipping data compiled by Bloomberg.


Net withdrawals from storage totaled 81 Bcf for the week ending January 11, compared with the five-year (2014–18) average net withdrawals of 218 Bcf and last year's net withdrawals of 208 Bcf during the same week. Working gas stocks totaled 2,533 Bcf, which is 327 Bcf lower than the five-year average and 77 Bcf lower than last year at this time.

According to The Desk survey of natural gas analysts, estimates of the weekly net change from working natural gas stocks ranged from net injections of 55 Bcf to 92 Bcf, with a median estimate of 82 Bcf.

The average rate of net withdrawals from storage is 31% lower than the five-year average so far in the withdrawal season (November through March). If the rate of withdrawals from storage matched the five-year average of 15.5 Bcf/d for the remainder of the withdrawal season, total inventories would be 1,309 Bcf on March 31, which is 327 Bcf lower than the five-year average of 1,636 Bcf for that time of year.