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Last Updated: October 12, 2017
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Oil prices will be lower for longer—that is the conventional wisdom. Data suggests, however, that  oil supplies are tightening and that higher prices are likely in the relatively near-future.

Refined Product Demand and Crude Oil Exports

U.S. crude oil plus products comparative inventories have fallen 120 mmb (million barrels) in 26 of the last 32 weeks (Figure 1). Strong domestic demand for refined products and increased crude oil exports are the main reasons. That translates into lower net imports of both crude oil and petroleum products to the United States. The year-to-date average of U.S. product net imports is down 0.5 mmb/day from 2016. That’s 3.5 mmb/week which is about the average weekly storage withdrawal since mid-February.

uploads1507791513398-3.3-mmb-week-470-kb-d-Decrease-in-Net-Petroleum-Product-Imports-.jpg

Figure 1. Approximately 3.3 mmb/week (470 kb/d) Decrease in Net Petroleum Product Imports Account for Most Inventory Reductions in 2017. Comparative Inventories Have Fallen 126 mmb Since Mid-February. Source: EIA and Labyrinth Consulting Services, Inc.

U.S. crude oil exports have increased reaching a record 1.9 mmb/d during the week ending September 29 (Figure 2).

uploads1507791573738-Record-Crude-Exports-of-1.9-mmb-d-Week-Ending-Sept.-29-2017-.jpg

Figure 2. Record Crude Exports of 1.9 mmb/d Week Ending Sept. 29 2017. Source: EIA and Labyrinth Consulting Services, Inc.

Increased exports have been part of  how producers cope with limited U.S. refining capacity for the ultra-light oil from tight oil plays. Recent increases in exports levels, however, are because of higher international oil prices compared with domestic prices.

Brent has traded at a premium to WTI since U.S. tight oil became a factor in global supply in late 2010. That was largely because of limited take-away and refining capacity for the new U.S. supply in the early days of tight oil production.  The Brent-WTI “spread” reached $28 per barrel in September 2011 but decreased when infrastructure caught up with supply. It averaged about $1.68 in the first half of 2017.

In June, the spread began increasing and is currently almost $7 per barrel (Figure 3). Some of this is a “fear premium” because of tensions in the Middle East—the GCC boycott of Qatar and the Iraqi Kurdish independence referendum. Some of it is also a buildup of inventories at the Cushing, Oklahoma storage facility and WTI pricing point.

uploads1507791622139-Brent-Premium-to-WTI-Has-Increased-More-Than-5-barrel-From-1H-Average-.jpg

Figure 3. Brent Premium to WTI Has Increased More Than $5/barrel From 1H Average. Middle East Fear Premium plus Cushing Inventory Levels are the Cause. Source: EIA and Labyrinth Consulting Services, Inc.

Inventory increases at Cushing may be partly explained by refinery and pipeline outages following recent hurricanes but the build ups actually began in July a month before Hurricane Harvey. The causes are not entirely clear but rising inventories at Cushing especially when its storage exceeds 80% is generally a negative factor for WTI prices.

In addition to crude oil, exports of distillate, liquefied petroleum gases, and liquefied refinery gases have also increased in 2017.

Comparative Inventories and The Yield Curve

Falling U.S. comparative inventories (C.I.) in 2017 is a trend and not an anomaly. Figure 4 shows the 120 mmb decrease in C.I. since mid-February and the associated “yield curve” (Bodell, 2009) that correlates inventory with WTI price.

uploads1507791687282-U.S.-Crude-Product-Comparative-Inventory-Has-Fallen-120-mmb-Since-Mid-February-1-1.jpg

Figure 4. U.S. Crude + Product Comparative Inventory Has Fallen 120 mmb Since Mid-February–Yield Curve Suggests Higher Oil Prices Sooner Than Later. Source: EIA and Labyrinth Consulting Services, Inc.

The magnitude of the inventory drawdown cannot be over-stated. The fact that it is driven by increasing demand suggests that that U.S. supply is moving steadily toward balance.

OECD comparative inventory (less the U.S.) has fallen 99 mmb since July 2016 (Figure 5). Although the data frequency is lower (monthly vs. weekly) and less systematic than U.S. inventory data, the reduction in C.I. is the main point.

uploads1507791801714-OECD-minus-U.S.-Comparative-Inventory-Has-Fallen-99-mmb-Since-July-2016-.jpg

Figure 5. OECD (minus U.S.) Comparative Inventory Has Fallen 99 mmb Since July 2016. Source: EIA, IEA and Labyrinth Consulting Services, Inc.

The relative lack of price increase with falling C.I. for both the U.S. and OECD is because the yield curve was flat for much of the reduction because of the the magnitude of storage volume. Now, enough inventory has been drawn down that the curvature of the trend is increasing. Greater price response with incremental reduction in C.I. is likely as volumes approach the 5-year average.

Misplaced Concern About Shale Supply

Fears about burgeoning U.S. supply from shale reservoirs has been a consistent drag on market sentiment about price for at least a year. This has been based more on rig count than real evidence. Continental Resources chairman Harold Hamm has loudly blamed overly optimistic EIA supply forecasts for low U.S. oil prices. This is misplaced and typical of the hyperbole regularly heard from shale company executives.

The fact is that U.S. output has been flat since early 2017 and the EIA has adjusted its forecasts as data replaces sampling algorithms in their accounting (Figure 6).

uploads1507791846990-U.S.-Output-Has-Been-Flat-in-2017-.jpg

Figure 6. U.S. Output Has Been Flat in 2017. Source: EIA and Labyrinth Consulting Services, Inc.

The reason is that despite increased drilling, frack crews and equipment are not sufficient to meet demand for well completions. Pressure pumping equipment was not maintained and parts were cannibalized after the oil price collapse, and crews were laid off. It may take another year of strong demand to rebuild this capacity.

The result is that far more tight oil wells are being drilled than completed and I expect that this pattern will continue (Figure 7).

uploads1507791943762-More-Permian-Wells-Have-Been-Drilled-Than-Completed-in-2016-2017-The-Number-of-DUCs-is-Increasing-.jpg

Figure 7. More Permian Wells Have Been Drilled Than Completed in 2016 and 2017. The Number of DUCs (Drilled Uncompleted Wells) is Increasing. Source: EIA and Labyrinth Consulting Services, Inc.

Fears that DUCs (drilled uncompleted wells) will flood the market with supply are unrealistic. When these wells are completed, it will be gradual and the natural ~30% annual decline in legacy shale production will be difficult to overcome. Moreover, production from the Eagle Ford and Bakken plays is declining. Only Permian production is increasing and on balance, it is unlikely that net shale production will increase much unless production trends outside the Permian basin somehow reverse.

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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