Guatemala Drill Team!! @ulterrabits Ready to… …

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WTI vs. WTI vs. WTI

The degree to which the perception of quality of West Texas Intermediate crude oil influences price was on display Wednesday in the form of the following crude value indication given to S&P Global Platts: WTI Midland at Cushing, Oklahoma, is worth 90 cents/b more than WTI at Cushing.

If that sounds confusing, it is, and let me explain.

West Texas Intermediate is the flagship US grade of oil produced in the Permian Basins of West Texas and transported by pipe, rail and truck to refiners near and far (like India far). The value of WTI at Cushing, Oklahoma, is the most commonly accepted benchmark for crude sales in the Americas for varying types of crude oil produced onshore and offshore in the US. It’s called “Cash WTI.”

WTI at Cushing also forms the backbone of the de facto North American crude oil futures contract, CME Group’s NYMEX WTI Light Sweet Crude Oil, which for simplicity’s sake we’ll call NYMEX Crude from now on. Launched in March 1983, historically, it was often colloquially referred to in the market as “NYMEX WTI,” even though WTI was one of many grades that could be delivered at Cushing against the contract, which caused uncertainty.

“Confusion over what is sold has led to problems, Merc officials say,” an Associated Press article from August 1990 reads. “Some buyers who thought they were getting WTI have discovered they were getting a different grade.” That led the NYMEX at the time to tell the market it should refer to the contract as light sweet crude instead of WTI, though the three-letter acronym persists to this day.

CME says NYMEX Crude represents light sweet crude oil meeting a series of specifications including 37-42 API, less than 0.42% sulfur and other parameters, which includes WTI-type light sweet crude streams as well as other blends referred to as Domestic Sweet, or DSW, that meet those specs.

To simplify: NYMEX Crude is WTI that meets NYMEX parameters, as well as other crudes, which may be blends, that meet NYMEX parameters. Blended crudes aren’t bad, but the possibility that a buyer may get one is an uncertainty, and uncertainty leads to lower bids for the unknown and higher bids for the known.

The difference between physical, NYMEX-spec WTI and the NYMEX contract is what’s called the exchange-for-physical, or EFP, which on Wednesday was heard to have traded at 2 cents/b. Therefore, physical WTI that meets NYMEX specs is worth 2 cents/b more than plain-old NYMEX-suitable crude.

Returning to that first price indication for WTI Midland at Cushing. Someone appears willing to pay a 90 cent/b premium to NYMEX-suitable WTI for pure, unblended WTI direct from the Permian to Cushing. An absolute guarantee of quality is nearly a full dollar over what, in theory, should be the same grade, if you figure that all WTI is Midland WTI.

Refiner worries about the significant amount of blending that goes on at Cushing — where crudes from all around North America comingle — has led to a significant price difference between DSW (NYMEX crude that isn’t WTI), NYMEX-suitable WTI, and virgin WTI from Midland.

That’s confusing.

To ease the confusion, CME Group in mid-December said it would amend Chapter 200 — essentially the rulebook for the NYMEX Crude — by adding additional quality requirements for physical crude deliveries against the January 2019 contract month and beyond.

Its move followed an identical move announced one day earlier by Enterprise Products Partners, one of two midstream outfits to which pipeline access is a must for barrels to be included in NYMEX Crude delivery. (The second, Enbridge, does not appear to have expanded its definition of WTI.)

“CME Group is amending the contract specifications to include five additional quality test parameters which will provide assurance that the quality and integrity of West Texas Intermediate (WTI) is maintained,” the exchange said at the time.

The changes have been applauded by refiners — largely through their work via the Crude Oil Quality Association, which recommended the Enterprise- and CME-adopted changes — but it remains to be seen whether this results in a narrower spread between “pure” WTI Midland at Cushing and WTI at Cushing that’s suitable for NYMEX delivery. In other words, as a result of the changes, does the perception of WTI at Cushing — or Domestic Sweet — improve?

One notable point: Enterprise and CME kept the API ceiling at 42 degrees in their mid-December changes. (In their defense, the COQA does not appear to have suggested any changes to API or sulfur.)

Platts Analytics data suggests the majority of the oil coming out of the Permian Delaware and Permian Midland basins is skewed toward light-sweet. Three of four crude assays for non-Cushing WTI provided to Platts since November showed API gravity of more than 42 degrees — 42.2, 43 and 43.4 — that wouldn’t be suitable for NYMEX delivery. That WTI isn’t on-spec to be called WTI.

In its revised specs, CME Group ditched the uncommon grades — Low Sweet Mix (Scurry Snyder) and New Mexican Sweet, among others — but will continue to allow blending of domestic crudes so long as they meet the same specs deliverable WTI must meet.

In 2018 alone, my boss and I have spoken with buyers of US crude in Singapore, India, China, South Korea, Japan and Northwest Europe. The overwhelming consensus about US crude quality has been that it varies dramatically, and blends are bad. By and large, US exporters can forget about selling DSW abroad for the moment.

If we’ve learned anything in the more than two years since US crude export restrictions were lifted, it’s that globally, refiners are well aware of the sophisticated blending operations in the US and are wary of anything that hints of a blend. That’s why buyers are asking for “WTI Midland” instead of just “WTI” — to be sure they’re not getting WTI via Cushing.

But judging by the continuing price spreads between DSW, NYMEX WTI and unblended WTI Midland, all at Cushing, it appears US refiners are just as picky as those outside of the US.

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Lithium to remain cornerstone of EV battery technology

Demand for lithium, one of the key materials used in making lithium ion batteries, is rising rapidly. The metal is used in a wide variety of industrial applications including glass, ceramics and greases, but it’s the use of lithium as a key component in the batteries that power electric and hybrid electric vehicles that has so excited markets.

Lithium does not occur naturally in nature. Instead it is found in a variety of mineral salts which needs to be chemically processed to form the lithium compounds and chemicals required by industry. A number of lithium compounds are used by industry but it is lithium carbonate that is the most commonly used form of lithium, accounting for more than half of total demand. The lithium industry often expresses lithium production and trade in lithium carbonate equivalent (LCE) units.

If electric vehicles, which rely wholly or partly on electricity stored in batteries as their source of energy, revolutionize road transport in the way many expect, demand for the metal will rise exponentially. China will be at the forefront of this.

China is already the world’s largest market for EVs, accounting for nearly half of global sales last year. This trend is expected to continue, supported by government policies driving the development and adoption of electric vehicles. This will require a significant increase in both lithium carbonate and increasingly lithium hydroxide, another lithium compound, which is the preferred basis for the next generation of lithium battery technologies.

China accounted for slightly more than half of total global production last year producing 123,000 tons LCE, according to statistics from the China Nonferrous Metals Industry Association (CNMIA). Of this, 83,000 tons was lithium carbonate with the remainder comprising other compounds like lithium hydroxide, lithium chloride and lithium metal.

China is very reliant on imported raw materials with many Chinese producers using concentrated spodumene, a mineral form of the metal mainly imported from Australia, to produce products including lithium carbonate. This is expensive and the cost of producing a ton of lithium carbonate at some Chinese producers using imported spodumene is reported to be more than $10,000 a ton. In contrast, producers like those in Chile that produce lithium carbonate from mineral brines may have costs under $2,500 a ton.

Strong lithium demand over the last few years has seen high-cost Chinese producers using imported spodumene set the marginal price. This has been reflected in the average price of imported lithium carbonate, which has more than doubled over the past year and a half, according to customs data. The price of battery-grade material is even higher, with S&P Global Platts assessing battery-grade lithium carbonate CIF North Asia at $17,250/mt in early June.

With demand continuing to outstrip supply and prices holding at elevated levels, imports remained strong in the first quarter of this year, rising 13% on the same period in 2017.

In a bid to secure future supplies Chinese companies have therefore been looking overseas. China’s Tianqi Lithium controls 51% of Talison Lithium, the world’s largest spodumene producer, most of which is shipped to China. And in May Tianqi Lithium also bought 24% of Chile’s SQM, the world’s lowest-cost lithium producer. This should support continuing imports of lithium carbonate into China even whilst a number of new Australian spodumene projects come online.

Chinese Lithium Carbonate Imports

One unique feature of the Chinese electric vehicle market is the popularity of battery (BEV) and plug-in hybrid (PHEV) electric buses. Due to city governments favoring cleaner battery technologies over diesel engines, EV buses last year accounted for over 20% of total sales of buses in China. This contrasts markedly with passenger BEV and PHEV volumes, which although much higher in absolute terms, accounted for under 2.5% of total car sales.

Chinese Sales of BEV and PHEV passenger cars and buses

A new policy introduced this year to promote development and production of EVs is expected to change the landscape for EVs in China. Though ambitious, it could see annual EV sales reach 7 million units by 2025, accounting for 20% of new passenger car sales.

The scale at which Chinese EV battery production capacity is expected to rise to meet this demand can be seen in the recent IPO prospectus by battery maker CATL. It forecasts that EV battery capacity will rise by nearly five times by 2022 to meet the demands of both local and foreign vehicle manufacturers in China, which are ramping up production and development of BEV and PHEV vehicles to comply with the new policy.

Historical and forecast production of batteries for New Energy Vehicles in China


This increase in battery production will see a significant rise in demand for metals like cobalt, nickel and lithium. Lithium carbonate is currently the predominant form of the metal used by battery makers in China, where it is used in the LFP (lithium-iron-phosphate) batteries that are commonly used by Chinese vehicle manufacturers including BYD, FAW-Volkswagen, Geely and Great Wall Motors.

Newer battery technologies like NCA (nickel-cobalt-aluminum) and NMC (nickel-manganese-cobalt) produce more energy for their size than LFP technology, but are more expensive owing to the use of nickel and cobalt. Regardless of the battery technology and the amount and proportions of other metals, the lithium intensity of batteries — the amount of lithium used per unit of energy the battery produces — remains more or less the same. While lithium intensity is expected to decline slightly over the next decade, this will be offset by a shift to larger battery packs to give EVs the range that consumers demand.

The next generation of NCA and NMC 811 batteries, which use eight parts nickel to one part each of manganese and cobalt, will favor the use of lithium hydroxide. However, it is likely that LFP batteries will continue to be used in China. LFP batteries do not provide as much energy as an NCA or NMC battery of the same weight, but in addition to being cheaper to produce they have a higher thermal stability, making them safer. NCA batteries in particular can be unstable and prone to overheating, causing fires. LFP batteries are therefore likely to continue to be used in China, especially in vehicles like electric buses where safety is of paramount importance.

The battery packs used in BEV and PHEV buses are on average much larger than those found in passenger cars, which means that they have been a significant driver of lithium demand. Indeed, S&P Global Platts estimates that in 2017 buses accounted for around 45% of all lithium demand from the Chinese EV sector.

Estimated lithium carbonate demand from Chinese EVs

Given the government’s desire to reduce air pollution and develop China as a leader in EV technology, we think that commercial vehicles, and buses in particular, will continue to be significant driver of EV penetration in China in the years ahead.

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It’s a steel cage fight for product exclusions in the underground tariff wars

Steel consumers and producers in the US are duking it out.

The battle is mostly under the radar and in the back rooms and alleys surrounding the Trump administration’s chaotic trade policy.

Tariff headlines tend to concentrate on the alienation of allies and Canadian Prime Minister Justin Trudeau’s “special place in hell.” However, aside from all the grappling amongst trading partners, day-to-day steel consumers are digging in to the US government’s harmonized tariff schedule in an attempt to maintain supply chains.

There are two categories of steel imports now in the US, those subject to the 25% Section 232 tariffs and those that are not. Non-tariff steel is coming from a small number of countries that have reached quota deals with the US — South Korea, Brazil, Argentina and Australia.

If you are an American steel consumer and sourcing material from anywhere other than these four countries, the only hope of avoiding paying the 25% tariff is to request a product exclusion. All a company needs to do is provide enough evidence that there is not sufficient production available in the US, or that the steel is needed for specific national security applications.

So far, the US Department of Commerce is wading through about 20,000 steel product exclusion requests. It has been able to post over 8,000 for a comment period, rejected another 2,000 and still has about 9,300 pending. The requests are more than quadruple the 4,500 Commerce expected to be filed.

Still, Secretary of Commerce Wilbur Ross assured the Senate Finance Committee Wednesday there was no need to worry, that the agency he heads is diligently working through the backlog. The department is set to release decisions on 98 requests, or about 0.5% of the total, this week.

Ross said Commerce is accelerating the process by immediately approving requests that are submitted correctly and have no objections against them.

The problem is, domestic steelmakers’ opinions are markedly different to those of their consumers on the criteria for an exclusion. Specifically, how readily available domestic supply is, and no one really knows what the specific national security considerations entail. The national security oriented Section 232 case is not limited to the needs of the Department of Defense, but to national interest in general.

The exclusion requests have generated about 4,000 objections from other domestic consumers and suppliers.

Semi-finished steel slabs are one of the most hotly contested product groups causing a split between domestic producers and consumers. US companies whose business model is based on rolling slabs into finished flat steel all rely on slab imports.

Brazil has reached an export quota deal with the US, but other major slab exporters have not. Slabs from Russia, Mexico and Japan are subject to the 25% tariff, a situation that could seriously impact companies like NLMK, Evraz, ArcelorMittal/Nippon Steel Calvert and California Steel Industries unless exclusions are granted or supply chains are retooled.

In an interview with S&P Global Platts at the end of March, NLMK USA CEO Bob Miller estimated that paying a 25% tariff on slab could tie up $60 million-$75 million during the estimated 90-day product exclusion process.

US flat-rolled steel producers have been objecting to the companies’ exclusion filings, arguing there is enough slab supply domestically should idled steelmaking capacity be brought back online. Over the last few months, US Steel announced the restart of two blast furnaces at its Granite City Works in Illinois and AK Steel is still sitting on an idled furnace at its Ashland Works in Kentucky.

The objections to NLMK’s filing say the company has access to domestic slab, but continues to rely on imported slab to maximize its profits. Before the Section 232 investigation, a company maximizing profits did not seem like such a crazy idea. But under a broad definition of national security, US steelmakers with underutilized production capacity are crying foul. It is becoming a patriotic duty to cast that slab in the US even if it is to supply a competitor. Still, it remains to be proven whether this would occur at a rate high enough that said competitors would be competitive or at a price level that would allow the suppliers to maximize profits.

“Thus, it is clear that NLMK’s product exclusion requests are designed to eviscerate any benefit the 232 [tariffs] could have for the US industry and are indicative of intentionally malicious actions by NLMK to damage American steel producers and their workers,” US Steel said in its objection to NLMK’s slab exclusion requests.

NLMK is seeking around 85 different tariff exclusion requests for some 3.5 million st of slab, well above the steelmaker’s historical slab consumption.

The size of the request is raising red flags for other domestic steel producers too.

However, Miller described the additional tonnage as a function of the Department of Commerce’s filing requirements. Product exclusion requests are made on a narrow HTS code basis and are required for every specification.

“When we first filed [exclusion requests] on tariffs, we used the codes for what we historically brought slabs into the country under,” Miller said. The initial submissions resulted in just six filings, but due to the narrow HTS definitions the company ended up filing around 85.

Also, NLMK USA filing for more tons than historically needed is a result of exclusions being awarded on an individual product basis and the company being unsure what, if anything, will be excluded. It is an attempt to ensure flexibility for supplying customers, according to Miller. “I have no plans of bringing in slabs and reselling them if that is what they are insinuating,” Miller added.

So, with all of this playing out publicly, the end result is still uncertain. Steel consumers remain in a “bureaucratic twilight zone,” waiting to see if the products they import will escape the tariffs, according to Senator Ron Wyden, Democrat-Oregon. Many of them will not. There is a high probability a number of the requests will be rejected, Ross said, but consumers are expected to keep fighting.

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Iraqi crude oil imports to USGC up, others fall: In the LOOP

Imports of Iraqi crude into the US Gulf Coast increased so far in 2018 while there have been fewer cargoes from Venezuela, Saudi Arabia, Mexico and Kuwait, according to the most recent data released by US Customs Bureau data.

From January to mid-June, US Gulf Coast refiners have imported more than 90 million barrels of Iraq’s light and heavy Basrah crudes, a 14% rise from 79 million recorded in the same period of time in 2017. However, USGC refiners bought only 60 million barrels of oil produced by Saudi Arabia in the same period, which is half of the 124 million barrels imported in the same period in 2017.

Kuwait also saw reduced demand for its crude from US refineries located in the US Gulf Coast, with only 8 million barrels of crude imported from January to mid-June compared with 18 million barrels in 2017. Because of a declining crude production in Mexico, imports of Maya crude into the US Gulf Coast fell to 90 million barrels, a drop of 3.3% from the 93 million barrels recorded during the same time period in 2017.

Despite decreased Venezuelan production, Venezuela still ranks among the top five countries from which USGC refiners are buying crude. Venezuelan grades amounted to 75 million barrels year to date, almost half of the 111 million seen in the year-ago period. More Iraqi barrels have been imported into the US Gulf Coast this year as fewer cargoes of Saudi Arabian oil have been sent following production cuts.

There also has been a reduction in available Maya crude and Venezuela crude as production in Venezuela has stagnated. Despite the average price of Maya crude deliveries to the USGC being at $59 year to date, US refiners bought more barrels from Iraq at an average of $64, according to Platts data. Maya crude prices have been weighed down recently by the sharp widening of WTS (West Texas Sour).

The WTS differential, which makes up 40% of the Maya pricing formula, has fallen in 2018 as Permian Basin production has outpaced takeaway capacity, causing bottlenecking. The WTS 30-day rolling average is at a $9.65/b discount to WTI cash.

The differential reached its widest point of the year on May 5, when it was assessed at WTI cash minus $13.75/b. The shifts in US crude imports and availability in the market could change once again as OPEC and its allies consider increasing output during their meeting later this week.

All eyes are on OPEC this week as any output increases would put more medium, heavy sour crudes in the market. However, if the group and its allies decide to maintain the current cuts, the supply of such crudes will tighten even further. Because of the tightened market, Gulf Coast sour crude benchmark Mars has been on a fairly steady rise since February.

The Mars differential to WTI cash hit its highest point since January 2014 in early June, when it was assessed at WTI cash plus $5.80/b. US Gulf Coast sour crudes strengthened Monday for the first time in a week and saw Mars 35 cents/b stronger day on day at a $3.45/b premium to WTI cash.

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The great scrubber conundrum

It’s been six months since my last 2020 dispatch. Since then, I’ve spent time at major industry gatherings in London (IP week) and Athens (Posidonia) and yet I’m just as uncertain about 2020 as I was then. My only comfort is that judging by my numerous conversations at Posidonia, I’m far from alone.

By now, anyone remotely involved in shipping should know about the importance of January 1, 2020 — the date environmental restrictions on sulfur content in bunker fuel come into effect. Some still hold out hope for an extension, but that just won’t happen. Much like most of the world, shipping has to become a more environmentally conscious industry.

For me, the biggest surprise at Posidonia was the intense interest in Exhaust Gas Cleaning Systems, or scrubbers, as a fuel compliance solution. Scrubbers — which allow ship operators to burn high-sulfur fuels — come in three forms: open loop, closed loop and hybrid. The first releases the excess sulfur dioxide into the sea, the second requires discharge at shore, while the latter can be operated as either of the other two.

Some owners have vocally opposed scrubbers, citing energy inefficiency and high maintenance costs. At Posidonia, a prominent Greek owner described them as “an experimental drug” forced onto the industry — a view likely shared by other industry luminaries.

On the other hand, some charterers are all for them, perhaps an early charterhire negotiating move to counter higher freight rates due to the increased bunker prices expected in 2020.

Discussion and announcements on scrubbers proliferated during the Posidonia week, leaving small, cash-strapped owners scratching their heads. Some affluent shipowners are hedging their bets, opting for scrubbers on half their fleet and confident of yard space availability. Moreover, one scrubber manufacturer was boasting about the flurry of orders he received during Posidonia week.

I’m more skeptical about scrubbers; assuming a Panamax vessel with a top-tier quality engine allowing for a quick retrofit could cost the owner some $2.5 million on a two-week drydock trip, as well as the loss of income during the installation. For affluent owners, cash prepayment might be an option, while cash-strapped owners will have to obtain additional financing, adding some 7%-10% to the cost. And that’s assuming financing is available.

Or take a 5-year-old 82,000 dwt Panamax dry bulk owner who requires additional scrubber financing. We assume a 24-month facility on 60% financing for the scrubber, with monthly capital repayments.

Say the ship is on a 12-month timecharter at $14,500 per day. The scrubber financing will add $2,000 to the daily expenses, taking the daily total to about $8,000 per day, excluding any interest or finance costs on the vessel herself. Assuming debt repayment on the vessel also, the vessel could be forced into negative cash-flow. Are small owners willing to sacrifice returns, just as the market seemingly begins to recover?

And what of fuel availability? Scrubber technology was seemingly out of fashion for months, only to become relevant again during recent weeks. Refiners and suppliers have been gearing up for compliant low sulfur fuel availability, leaving some operators asking whether high sulfur fuel will be available post-2020.

While being in the dark is disorienting, it can also be fascinating and exciting, though for owners it must be nerve-wracking. Time runs short and decisions must to be taken soon.

And we haven’t even touched on the equally onerous Water Ballast Treatment bill coming up…

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China hits back at Trump, but LNG stays untouched

Given the central role that both countries envisage for bilateral LNG trade in their national energy strategies in the years ahead, it was not entirely surprising that Beijing opted to exclude LNG from its threat to impose an additional 25% tariff on $50 billion worth of US goods, including energy and agricultural products.

LNG is playing an increasingly important role in China’s energy security. China surpassed South Korea as the world’s second largest LNG importer in 2017, its LNG demand is on track to hit 47 million mt in 2018 and could exceed that of Japan by 2030, as Beijing seeks to raise the proportion of gas in the country’s energy mix to 15%, according to S&P Global Platts Analytics.

China’s dependence on US LNG is also on the rise. This is supported by a ramp-up in US Gulf LNG production, declining supplies from Southeast Asian legacy producers and limited spot availability from eastern Australia, where rising domestic gas prices have created political opposition to LNG exports. China has imported around 1.61 million mt so far in 2018, almost as much as it imported in the full year 2017.

Meanwhile, rebalancing fundamentals in Asia Pacific have continued to push up prices, with the Platts JKM averaging nearly $9/MMBtu over January-May 2018, up from $6.5/MMBtu a year earlier. This has made inter-basin trade inflows from the Atlantic and the US Gulf Coast increasingly vital to meet Asia’s spot demand and balance regional fundamentals, especially over the peak winter demand period.

Related blog post:
Commoditization underpins LNG demand, supply and pricing innovations

The US-China bilateral LNG trade not only plays a role in short-term fundamentals and supply security. Long-term energy agreements backed by Chinese companies have underpinned US LNG projects such as Cheniere’s Corpus Christi Train 3, Delfin floating LNG and the Alaska LNG project, and helped ensure additional LNG supplies are ready to come online as the LNG market marches towards a supply squeeze in the early-mid 2020s.

The trade war between the US and China escalated on Saturday with China threatening an additional 25% tariff on $50 billion worth of US goods, including energy and agricultural products, in response to President Donald Trump’s decision to place similar tariffs on the same annual value of Chinese product imports.

Among the $50 billion worth of US goods, the additional tariff on a total $34 billion worth of US agricultural products, cars and marine products are due to come into effect on July 6, according to an announcement by the Customs Tariff Commission of the State Council.

Additional duties on the remaining $16 billion of US goods, including crude oil, LPG, gasoline, naphtha, fuel oil and natural gas, will be announced at a later date.

The latest tariff threat between the two biggest economies comes less than a month after Beijing and Washington on May 19 inked an agreement to put the brakes on their trade dispute after China agreed to buy more US goods, key among them being LNG and crude oil.

US tariffs and China’s retaliatory rhetoric have emerged as a big risk for commodity demand and prices in 2018, alongside a slowdown in the Chinese economy and geopolitical uncertainty.

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Oil and Gas Trade Show Leaves Me Wanting

I went to the Global Petroleum Show with high digital hopes, and came away pretty disappointed. The vast majority of suppliers to the industry are just not in the game. The Global Petroleum Show For readers outside of Alberta, the Global Petroleum Show is an…

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The curious case of China’s missing trade data

The longer China delays publishing its detailed trade data for April, the more it is feeding speculation about the possible ulterior motives behind withholding the numbers, and hurting credibility.

Also, with the amount of geopolitical upheaval going on, the transparency of future Chinese trade data releases is being questioned with each passing day as market participants harbor growing suspicions about Chinese intent.

A source close to the government said it was highly likely that future data releases from China would contain fewer details and be published with a greater time lag.

This does not bode well for Chinese economic data in general, which has been the subject of controversy and scrutiny in the past. The government’s refusal to offer any explanation beyond “technical issues” only compounds the problem.

China’s General Administration of Customs usually releases detailed import/export data for a given month in the fourth week of the following month, according to a table on its official website.

China crude imports from Iran

But on May 25, when detailed data for April was due, a gaggle of economists, analysts, traders and data geeks were left empty-handed. So far, half of June has passed and it remains unclear when Beijing will release the numbers.

“It is a really worrying situation. The Chinese administration, as a member of the World Trade Organization, has the obligation to open its trade data to the world in a timely manner,” a Hong Kong-based market observer said.

There was also some speculation that the move was due to GAC’s investigation on illegal data distributors.

Another view, from some analysts at trading companies was that the delay might be a result of the Chinese government’s re-organization, which started in March, possibly leading to changes in data release by the GAC.

However, there has been no official announcement that they would be carrying out investigations or making changes to the data release, and instead have given the reason of “technical issues.”

A worse time couldn’t have been picked for the “technical issues.”

Trade tensions between China and the US have dragged for more than three months, and a detailed plan for Beijing to narrow its significant trade deficit with Washington is yet to be disclosed.

Analysts, who rely on monthly numbers to update economic forecasts, said official trade data is far more sensitive to negotiations than ever before.

Then there is the issue of crude oil and refined oil products trade with Iran.

China and Iran agreed to strengthen strategic cooperation during Iranian President Hassan Rouhani’s visit to China during the Shanghai Cooperation Organization summit in early June, even as the US pulled out of the Iran nuclear deal.

The SCO agreement will possibly pave the way for steady crude flow from Iran to China — data which was typically included in China’s monthly numbers. When it was still being published, the data set included China’s goods imports by country of origin and China’s exports by destination.

China is currently the largest customer of Iranian crude, and did not reduce crude imports from Iran even during the height of the last sanctions against Tehran in 2012.

Over 2011 to 2017, Beijing imported 441,000-627,000 b/d of crude from Iran, according to GAC data. In the first quarter of 2018, China’s imports of Iranian crude rose 17.3% year on year to 658,000 b/d, making Iran its sixth-biggest supplier.

International buyers of Iranian oil have until November 4 to wind-down contracts before the US re-imposes sanctions on the oil, energy, shipping and insurance sectors, a US Treasury Department fact sheet showed.

From Beijing’s perspective, why publish numbers that incriminates itself.

From everyone else’s perspective, how reliable will China’s numbers still be going forward?

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Commoditization underpins LNG demand, supply and pricing innovations

LNG’s increasing flexibilities are facilitated by increasingly transparent market-based pricing, soaring derivatives trade and new Asian hubs emerging. Last month, Cheniere successfully sanctioned its latest supply project by offering market-friendly flexibilities and cost competitiveness, additional drivers underpinning LNG’s commoditization.

Certain buyers, sellers, traders and exchanges have therefore already benefited from the new LNG environment, and further opportunities exist. During S&P Global Platts’ annual LNG and Natural Gas Markets Asia Conference, held May 31-June 1 in Singapore, market participants demonstrated many innovative approaches for grasping the opportunities offered by LNG’s increasing commoditization.

1. Emerging Asian hubs providing further LNG demand and liquidity

Australia’s AGL Energy is targeting a final investment decision (FID) next year on a project to import LNG into Australia by 2021. AGL is currently negotiating with LNG suppliers and FSRU (floating storage and regasification unit) providers for deliveries into Victoria, from where existing pipelines could transport the regasified LNG to domestic markets in South Australia, New South Wales and Tasmania.

Combined with AGL’s Australian gas storage facilities, this could underpin the emergence of a liquid Victoria gas/LNG hub.

East coast gas market supply gap continues to grow

Source: Presentation by AGL Energy’s Phaedra Deckart at Platts LNG & Natural Gas Markets Asia Conference, Singapore, June 1 2018.

This trend towards greater Australian gas/LNG flexibility is also evident in Queensland, where Gladstone LNG is already a portfolio player, optimizing gas deliveries between domestic and export markets, depending on eastern Australian gas economics and politics.

Elsewhere in Asia, Thailand is another emerging hub, with state-owned PTT planning to harness its Map Ta Phut regas terminal to offer LNG bunkering and small-scale distribution to its existing truck loading facilities.

Thailand's future LNG business opportunities

Source: Presentation by PTT’s Thanaporn Rugtrakul at Platts LNG & Natural Gas Markets Asia Conference, Singapore, May 31 2018.

While strong recent northeast Asian LNG buying has been well documented, new tranches of Asian demand could also ramp up. This includes over 40 potential small-scale LNG demand locations across Indonesia, starting at around 30 billion Btu/day (about 200,000 mt/year of LNG), supplied by the country’s production hubs, according to PGN LNG. Realizing this potential primarily hinges on competitive LNG pricing, as the required small-scale LNG ships and receiving terminals, to supply 30 billion Btu/d, add over US$3/MMBtu to Indonesian FOB LNG prices.

Demand acquisition play important role for cost competitiveness

Source: Presentation by PGN LNG’s Melati Sarnita at Platts LNG & Natural Gas Markets Asia Conference, Singapore, June 1 2018.

2. Increasingly transparent, market-based, LNG pricing harnessed

Malaysian state-owned Petronas outlined its intentional allocation of some uncontracted LNG for innovative optimization and for the purpose of enhancing LNG price discovery. As part of this initiative, the company successfully sold its first LNG cargo through the online trading platform GLX last month.

Both Pakistan LNG and Sui Southern Gas Company highlighted Pakistan’s transparent LNG procurement processes, which are facilitating the country’s rapidly growing LNG imports. This includes competitive bidding for Pakistani spot/short-term purchases as well as long-term supplies from Gunvor, Eni and Trafigura, with the LNG-to-Brent pricing slope publicly available.

RWE said that, given LNG pricing’s increasing complexity, the Platts JKM market represents an effective risk-management tool for LNG spot pricing and is also an effective tool for LNG price formation, supporting price transparency and price awareness.

Intercontinental Exchange (ICE), the largest clearer of JKM derivatives, shared details on the rapid growth in traded volumes as well as tenure length. In May 2018, 3.5 million mt of JKM derivatives cleared on ICE and CME, representing more than fourfold year-on-year growth, in addition to OTC volumes.

The evolving term structure in JKM futures

Source: Presentation by ICE’s John Ho at Platts LNG & Natural Gas Markets Asia Conference, Singapore, June 1 2018.`

3. Liquefaction FIDs depend on sponsors/financiers successfully evolving with LNG’s commoditization

Since 2016, suppliers and financiers have struggled to adjust to LNG’s increasing flexibility, leading to a dropoff in liquefaction project FIDs. This hiatus was eased by Cheniere’s sanction of Corpus Christi train three, in May. To facilitate their sanction, US liquefaction trains typically offer destination flexibilities, LNG pricing diversification and cost competitiveness, all important facilitators of LNG’s commoditization.

Slowdown in LNG supply project FIDs

Source: Presentation by Cheniere’s Douglas Wharton at Platts LNG & Natural Gas Markets Asia Conference, Singapore, June 1 2018.

A non-US greenfield proposal, Mozambique LNG, is contributing to LNG’s commoditization by offering a combination of flexible DES (delivered ex-ship) contracts, buyer optionality as well as hybrid and multiple LNG pricing indexes.

Will Mozambique LNG contribute to commoditization

Source: Presentation by Anadarko’s Andrew Seck at Platts LNG & Natural Gas Markets Asia Conference, Singapore, May 31 2018.

Mozambique LNG’s strategic location also brings opportunities to become a future LNG price setter, by flexibly delivering cargoes to either West of Suez or East of Suez markets.

LNG from Mozambique -- A future price setter?

Source: Presentation by Anadarko’s Andrew Seck at Platts LNG & Natural Gas Markets Asia Conference, Singapore, May 31 2018.

Many players have already benefited from LNG’s commoditization and opportunities abound

A number of companies – including, as outlined above, Cheniere, ICE, Petronas and Pakistani players – are successfully evolving to grasp opportunities from LNG’s increasing commoditization. Additional LNG hubs could emerge in Thailand, Australia and, for small-scale deliveries, Indonesia.

Meanwhile, Pakistan, a fast-growing importer, as well as exchanges and traders, have already benefited from increasingly transparent LNG pricing. Cheniere last month proved the most recent adaptable supplier with its sanction of train 3.

It remains to be seen which will be the next LNG suppliers, buyers and financiers to successfully offer market-friendly flexibilities and cost competitiveness, facilitating their project FIDs, in 2018.

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