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Last Updated: March 21, 2016
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World oil prices are controlled by the amount of crude oil stored at Cushing, Oklahoma. That’s because Cushing is the pricing point for WTI (West Texas Intermediate) oil prices, the most-traded oil futures contract in the world.

Cushing Storage Rules World Oil Prices

WTI (and Brent) oil prices have good negative correlation with the volume of crude oil stored at Cushing. Comparative inventory, the present volume of oil compared with the 5-year average, and oil-price volatility, the rate at which the price of oil moves up and down.

From the beginning of 2014 until the end of July, comparative inventory fell and world oil prices were high averaging more than $100 per barrel. From August to the time of the November 28 OPEC meeting, Cushing inventories rose and oil fell below $70. OPEC’s decision not to cut production caused a spike in volatility and prices dropped to $46 per barrel by the end of January 2015.

Prices rose in February based on hope that falling rig counts would bring declining U.S. production. Rising Cushing inventories brought markets back to reality and they fell again in March.

Cushing storage fell from mid-April to mid-June 2015 and oil prices rallied to $60 per barrel. Concerns about China’s economic growth and the lifting of sanctions on Iran added to flattening Cushing inventories and oil fell to near $38 per barrel by mid-August.

When inventories fell again in late August, prices increased to almost $50 per barrel and then plateaued until the end of October. Storage had flattened but the outlook for Chinese growth had improved as the People’s Bank of China announced stimulus measures.

From the beginning of November to the end of 2015, comparative inventories increased again and oil prices plunged below $30 per barrel with the near-collapse of China’s stock markets.

Flattening comparative inventories in early 2016 and rumors of an OPEC production cut and then, a partial OPEC production freeze moved oil prices back above $30 per barrel where they have remained through February.

Expectation and reality both influence oil prices but Figures 1 and 2 show that the reality of Cushing comparative inventory change is the dominant factor. World economic and political events have the power to affect oil prices but without support from Cushing storage levels, these changes are relatively short-lived.

What Must Happen For Oil Prices to Increase

Cushing, Oklahoma is the largest oil-storage tank farm in the world. It has 73 million barrels of working capacity, about 13% of total U.S. storage. Several important oil pipelines converge there as oil moves from production sites to refineries on the Gulf Coast.

Cushing is the delivery and pricing point for West Texas Intermediate crude oil futures contracts. More than 3 billion barrels of WTI oil futures contracts are traded weekly. For the week ending February 26, 2016, the volume of WTI trades (3.1 million contracts) was nearly three times the volume of Brent ICE trades (1.2 million contracts). Each contract is for 1000 barrels of oil.

Few of these contracts result in delivery of physical oil. Instead, most contracts are sold forward to take advantage of the higher contango prices on later-dated contracts.

Limited refining capacity for the light, sweet crude oil from tight oil fields has resulted in the stock-piling of oil at Cushing. Since oil prices collapsed in 2014, it makes more sense to pay storage fees than to sell oil at a loss.

Storage volumes at Cushing have increased since the crude oil export ban was lifted in December. Since then, additions at Cushing have averaged more than 500,000 barrels per week and total U.S. storage has increased about 1.5 million barrels per week. Current storage capacity at Cushing is 89% full. As long as Cushing and Gulf Coast storage remain above 80% of capacity, oil prices will be low.

For oil prices to increase, Cushing inventories must fall. That means that both U.S. tight oil production, chiefly from the Bakken play, and Canadian light oil production brought by pipeline to Cushing must decline.

Bakken production was consistent in 2015 at about 1.2 million barrels per day. Canadian oil imports to the U.S. decreased from April through July 2015 and may have contributed to the fall in Cushing inventories that lead to a $15 per barrel increase in WTI prices. At the same time, decreased production from the Eagle Ford and Permian basin tight oil plays would free up storage in the Gulf Coast that might allow more oil to flow out of Cushing.

Although world events are important, Cushing comparative inventories dominate world oil prices. This does not mean that decreased production and inventories elsewhere in the world would not affect prices. It acknowledges, however, that increased North American unconventional oil production created the global over-supply that caused oil prices to collapse.

Given the history of the past 2 years, oil prices are unlikely to increase until U.S. and Canadian oil production decline enough to reduce Cushing storage. Recent flat comparative inventories suggest that near-term prices could go either way depending on flows in and out of Cushing.

A relatively small decrease of 3 to 5 million barrels in Cushing stocks could result in a $10 to $15 increase in WTI prices, similar to what happened from April through June of 2015. Conversely, an increase in stocks of a few million barrels may push oil prices into the low $20 range. It mostly depends on U.S. and Canadian unconventional oil production.

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Indonesia’s Abadi LNG Project Sees Movement

It has been 21 years since Japanese upstream firm Inpex signed on to explore the Masela block in Indonesia in 1998 and 19 years since the discovery of the giant Abadi natural gas field in 2000. In that time, Inpex’s Ichthys field in Australia was discovered, exploited and started LNG production last year, delivering its first commercial cargo just a few months ago. Meanwhile, the abundant gas in the Abadi field close to the Australia-Indonesia border has remained under the waves. Until recently, that is, when Inpex had finally reached a new deal with the Indonesian government to revive the stalled project and move ahead with a development plan.

This could have come much earlier. Much, much earlier. Inpex had submitted its first development plan for Abadi in 2010, encompassing a Floating LNG project with an initial capacity of 2.5 million tons per annum. As the size of recoverable reserves at Abadi increased, the development plan was revised upwards – tripling the planned capacity of the FLNG project to be located in the Arafura Sea to 7.5 million tons per annum. But at that point, Indonesia had just undergone a crucial election and moods had changed. In April 2016, the Indonesian government essentially told Inpex to go back to the drawing board to develop Abadi, directing them to shift from a floating processing solution to an onshore one, which would provide more employment opportunities. The onshore option had been rejected initially by Inpex in 2010, given that the nearest Indonesian land is almost 100km north of the field. But with Indonesia keen to boost activity in its upstream sector, the onshore mandate arrived firmly. And now, after 3 years of extended evaluation, Inpex has delivered its new development plan.

The new plan encompasses an onshore LNG plant with a total production capacity of 9.5 million tons per annum. With an estimated cost of US$18-20 billion, it will be the single largest investment in Indonesia and one of the largest LNG plants operated by a Japanese firm. FID is expected within 3 years, with a tentative target operational timeline of the late 2020s. LNG output will be targeted at Japan’s massive market, but also growing demand centres such as China. But Abadi will be entering into a far more crowded field that it would have if initial plans had gone ahead in 2010; with US Gulf Coast LNG producers furiously constructing at the moment and mega-LNG projects in Australia, Canada and Russia beating Abadi’s current timeline, Abadi will have a tougher fight for market share when it starts operations. The demand will be there, but the huge rise in the level of supplies will dilute potential profits.

It is a risk worth taking, at least according to Inpex and its partner Shell, which owns the remaining 35% of the Abadi gas field. But development of Abadi will be more important to Indonesia. Faced with a challenging natural gas environment – output from the Bontang, Tangguh and Badak LNG plants will soon begin their decline phase, while the huge potential of the East Natuna gas field is complicated by its composition of sour gas – Indonesia sees Abadi as a way of getting its gas ship back on track. Abadi is one of Indonesia’s few remaining large natural gas discoveries with a high potential commercialisation opportunities. The new agreement with Inpex extends the firm’s licence to operate the Masela field by 27 years to 2055 with the 150 mscf pipeline and the onshore plant expected to be completed by 2027. It might be too late by then to reverse Indonesia’s chronic natural gas and LNG production decline, but to Indonesia, at least some progress is better than none.

The Abadi LNG Project:

  • Reserves: 10 tcf of natural gas
  • Field: Estimated production of 1.2 bcf/d gas and 24,000 b/d condensate for 24 years
  • Operations: Inpex (65%), Royal Dutch Shell (35%)
  • LNG Plant: 9.5 mtpa capacity, estimated start date in 2027
June, 18 2019
Your Weekly Update: 10 - 14 June 2019

Market Watch

Headline crude prices for the week beginning 10 June 2019 – Brent: US$62/b; WTI: US$53/b

  • With US’s trade and tariff assault abating for the moment, crude oil prices have consolidated their trends to steady up as OPEC+ nations signal their desire to continue stabilising the oil market ahead of a June 25 meeting in Vienna
  • Despite some background squabbles between Russia and Saudi Arabia – with Russia at pains to emphasise its position regarding lower oil prices – the group has seemingly come together
  • Saudi Arabia has reportedly corralled the OPEC group to agreeing to extending the current supply deal to December, even Iran, but convincing Russia has been a harder task and adherence may continue to be an issue
  • Meanwhile, the US continues to tighten the screws on Venezuela and Iran, announcing sanctions on Iranian petrochemicals exports and targeting Venezuela’s trade in diluents that are used to blend heavy crude down
  • With reports that Iranian crude exports were down to an estimated 400 kb/d in May, tensions in the Persian Gulf continue with the latest incident being attacks on tankers; this risk factor will lift the floor for oil prices for now
  • After a brief rise last week, American drillers dropped 11 oil rigs but added 2 gas rigs according to Baker Hughes for a net loss of 9 active sites, bringing the total active rig count down to 975
  • As OPEC prepares to meet, the market has seemingly locked in an extension of the supply deal into projections, which will leave little room for gains; expect Brent to fall to the US$60-62/b range and WTI to trade at US$51-53/b

Headlines of the week

Upstream

  • BP is selling its stakes in its Egyptian concessions in the Gulf of Suez to Dubai-based Dragon Oil (a subsidiary of ENOC), which do not include BP’s core production assets in the West Nile Delta production area
  • Eni’s African streak continues with its fifth oil discovery in Angola’s Block 15/06 at the Agidigbo prospect, bringing total resources to 1.8 billion barrels
  • Also in Angola, ExxonMobil and its partners are looking to invest further in offshore Block 15 that will see Sonangol take a 10% interest in the PSA
  • Russia’s Lukoil has inked a deal with New Age M12 Holding to acquire a 25% interest in the offshore Marine XII licence in the Republic of Congo for US$800 million, covering the producing Nene and Litchendjili fields
  • Buoyed by recent discoveries in the Caribbean, the Dominican Republic is launching its first licensing round in July, offering 14 blocks in the onshore Cibao, Enriquillo and Azua basins and the offshore San Pedro basin
  • W&T Offshore and Kosmos Energy have struck oil in the Gladden Deep well in the US Gulf of Mexico, the first of a four-well programme that includes the Moneypenny, Oldfield and Resolution prospects with estimates of 7 mmboe

Midstream & Downstream

  • Shell is increasing storage capacity at its Pulau Bukom refinery in Singapore, adding two new crude oil tanks to increase capacity by nearly 1.3 million barrels
  • A new swathe of American sanctions against Iran is now targeting Iranian petrochemical exports, clipping a major regional revenue source for Iran
  • Angola is looking overhaul its refining sector, by attracting investment o overhaul facilities and building a new refinery in Soyo that will be the third ongoing refining project after the 200 kb/d Lobito and Cabinda plants
  • BP and Mexico’s IEnova have signed a deal allowing BP to use IEnova’s new gasoline and diesel storage and distribution facilities in Manzanillo and Guadalajara, allowing access to over 1 million barrels of storage
  • British petrochemicals firm INEOS has announced plans to invest US$2 billion in building three new petchem plants in Saudi Arabia that would form part of the wider Saudi Aramco-Total Project Amiral petrochemicals complex
  • The saga of Russia’s bankrupt 180 kb/d Antipinsky refinery continues, with SOCAR Energoresurs (a JV including Sberbank) acquiring an 80% stake in the refinery with the aim of restarting operations
  • Mexico has kicked off construction of its US$7.7 billion oil refinery, aimed to overhauling the Mexican refining industry after years of underperformance

Natural Gas/LNG

  • Toshiba is exiting the Freeport LNG project in Texas, paying Total US$815 million and handing over its 20-year liquefaction rights by March 2020
  • China’s CNOOC has officially acquired a 10% stake in the Arctic LNG 2 project by Novatek, solidifying natural gas ties between Russia and China
  • Cheniere has taken FID to add a sixth liquefaction train to its Sabine Pass export project in Lousiaina, which would add 4.5 mtpa of capacity to the plant
  • Novatek, Sinopec and Gazprombank have created a China-focused joint venture to market LNG and natural gas from Novatek’s Arctic projects in China
June, 17 2019
Upcoming OPEC Meeting: What to Expect

A month ago, crude oil prices were riding a wave, comfortably trading in the mid-US$70/b range and trending towards the US$80 mark as the oil world fretted about the expiration of US waivers on Iranian crude exports. Talk among OPEC members ahead of the crucial June 25 meeting of OPEC and its OPEC+ allies in Vienna turned to winding down its own supply deal.

That narrative has now changed. With Russian Finance Minister Anton Siluanov suggesting that there was a risk that oil prices could fall as low as US$30/b and the Saudi Arabia-Russia alliance preparing for a US$40/b oil scenario, it looks more and more likely that the production deal will be extended to the end of 2019. This was already discussed in a pre-conference meeting in April where Saudi Arabia appeared to have swayed a recalcitrant Russia into provisionally extending the deal, even if Russia itself wasn’t in adherence.

That the suggestion that oil prices were heading for a drastic drop was coming from Russia is an eye-opener. The major oil producer has been dragging its feet over meeting its commitments on the current supply deal; it was seen as capitalising on Saudi Arabia and its close allies’ pullback over February and March. That Russia eventually reached adherence in May was not through intention but accident – contamination of crude at the major Druzhba pipeline which caused a high ripple effect across European refineries surrounding the Baltic. Russia also is shielded from low crude prices due its diversified economy – the Russian budget uses US$40/b oil prices as a baseline, while Saudi Arabia needs a far higher US$85/b to balance its books. It is quite evident why Saudi Arabia has already seemingly whipped OPEC into extending the production deal beyond June. Russia has been far more reserved – perhaps worried about US crude encroaching on its market share – but Energy Minister Alexander Novak and the government is now seemingly onboard.

Part of this has to do with the macroeconomic environment. With the US extending its trade fracas with China and opening up several new fronts (with Mexico, India and Turkey, even if the Mexican tariff standoff blew over), the global economy is jittery. A recession or at least, a slowdown seems likely. And when the world economy slows down, the demand for oil slows down too. With the US pumping as much oil as it can, a return to wanton production risks oil prices crashing once again as they have done twice in the last decade. All the bluster Russia can muster fades if demand collapses – which is a zero sum game that benefits no one.

Also on the menu in Vienna is the thorny issue of Iran. Besieged by American sanctions and at odds with fellow OPEC members, Iran is crucial to any decision that will be made at the bi-annual meeting. Iranian Oil Minister Bijan Zanganeh, has stated that Iran has no intention of departing the group despite ‘being treated like an enemy (by some members)’. No names were mentioned, but the targets were evident – Iran’s bitter rival Saudi Arabia, and its sidekicks the UAE and Kuwait. Saudi King Salman bin Abulaziz has recently accused Iran of being the ‘greatest threat’ to global oil supplies after suspected Iranian-backed attacks in infrastructure in the Persian Gulf. With such tensions in the air, the Iranian issue is one that cannot be avoided in Vienna and could scupper any potential deal if politics trumps economics within the group. In the meantime, global crude prices continue to fall; OPEC and OPEC+ have to capability to change this trend, but the question is: will it happen on June 25?

Expectations at the 176th OPEC Conference

  • 25 June 2019, Vienna, Austria
  • Extension of current OPEC+ supply deal from end-June 2019 to end-December 2019
June, 12 2019