[Premium] Morten Frisch - Oil Prices And What They Mean for LNG: Analysis

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Although the LNG market is becoming more flexible with respect to trade and pricing, most medium and long-term LNG supply arrangements still have crude oil pricing; mainly linked to the reported price of Japan Customs-cleared Crude or JCC, the price of Brent blend crude oil or in some cases a combination of the two.

As a result, LNG buyers, traders and project promoters and their financiers all need to understand the crude oil market and the interplay between the two markets.

Since late 2016, Opec, led by Saudi Arabia and a group non-Opec producers led by Russia, have been trying to balance the crude oil market to increase prices. This article addresses the oil market perceptions and drivers which Opec and its newfound friends are trying to influence, if not control.    

A week is a long time in the oil market. On July 21, the oil market slowed down in anticipation of the fourth Opec-Non Opec Ministerial Monitoring Committee meeting in St Petersburg, Russia. The price for the US crude oil price marker, WTI, closed at $45.78/barrel. By July 31 and with no further production cuts resulting from the meeting – at least in part as a result of Saudi Arabia’s oil minister’s announcement of a subtle shift in Saudi Arabia’s strategy, moving from a focus on oil production to export volumes – the WTI price had risen to $50.21/b. Within one week, the WTI price marker had gained some 10% in value.

Data showing a decline in crude oil and petroleum product storage in the US and a slowing growth in the onshore oil rig count in the lower US 48 states added to the price rise. Commercial and speculative oil market players seemed to be forming the view that production from US shale or tight oil deposits – the world’s marginal crude oil supply source – would moderate in the future, allowing oil supply and demand to get back into balance. Although the price has softened by a couple of $/b since, it seems to hold up just below $50/b.

It is very likely that Opec and oil markets in general do not properly appreciate that, should the price of WTI again approach $60/b, growth in not only US, but also Canadian shale oil production would quickly come back with surprising strength. The price seems to be driven by, in order of perceived importance, the following factors:

1. Sentiment. Short term trading strategies and hedge funds’ management of outstanding positions, daily “headlines” of the impact of Opec meetings and/or other geopolitical developments as well as the interpretation of price movements on the basis of past experiences, continue to provide the kind of short-sighted, misleading view of the oil world that has been around in the market for a long-time. Since this is not a new phenomenon, experienced analysts should recognise such resulting short-term price fluctuations for what they are
2.  Misguided obsession with Energy Information Aministration’s (EIA) weekly US oil storage data. Albeit a key metric in the past decades when the US was not an oil exporter, this information is now of reduced significance. The weekly reported US commercial oil storage data, some 475mn b, is only a fifth of OECD’s commercial oil storage capacity; and only some 7% of the world’s total oil storage – an elusive number estimated in early 2017 to be around 8bn b (including strategic petroleum reserves and oil and oil products in floating storage). This focus on weekly US levels ignores the fact the US now exports some 2.5mn b/day of oil products and more than 1mn b/d of crude. The output mainly goes to Mexico and other countries in Central and South America, all lacking reliable and transparent oil storage data.
3. Importance attributed to EIA’s data showing falling shale oil production per rig, but failing to adjust for the number of drilled but uncompleted oil well (DUCs). According to statistics compiled by the EIA there were 6,031 shale oil and gas DUCs in the main US shale basins end June 2017, of which some 4,500 DUCs can be classified as oil wells. The number of oil DUCs is going up, particularly in the Permian basin, the shale oil and gas basin shared by Texas and New Mexico, where 2,244 of these oil DUCs are. This is 800 more than at the beginning of 2017. Should the price of WTI enter the $55-$60/b range, these 4,500 oil DUCs could be completed over a period of some 12 to 18 months with more than 1mn b/d of additional oil production entering the market. This is, of course, based on the premise that hydraulic fracturing and well completion crews are available for this work and also current processing and transportation constraints have been alleviated, particularly in the Permian Basin.

It is, however, a number of other factors, old and new, that will drive the future oil price, and they should not be overlooked. These are mostly again supply-side drivers and they are as follows: 

1. The Permian Basin is the world’s current marginal oil supplier. Permian oil producers were reported in July to have hedged 65% of their remaining 2017 production at $50/b, and 25% of their forecast 2018 output at $50/b, a number which will have increased when 2017 and 2018 WTI forward contracts started trading above $50/b in early August. Producers are likely to continue hedging and extracting oil fostered by the innovative drilling and production techniques which lowered their costs and helped them withstand the sustained low price levels of the 2015/16 oil price crash. Rising hire rates for new technology “super-spec” rigs needed to effectively drill long lateral wells from multi-well pads or the costs of renewing skilled crew contracts remain a concern, but efficiency improvements should more than counter-balance these cost rises. 
2. Private equity funds with creative financing arrangements have come forward to facilitate drilling activity. Drilling joint ventures – an energy industry “match-making” of investors and producers to mutually benefit from producer-owned idle land – raise productivity, release producer cash flow and secure attractive, up-front, short term returns for investors who also control the land as insurance against a default. Such arrangements driven by the current low interest environment, albeit public, are not necessarily yet registered or included in any recent analysis of the resilience of the US shale oil industry. 
3. Midstream bottlenecks and the lack of “take away” capacity – in the form of pipeline capacity shortages or processing constraints – could impact on US shale such that Permian Basin oil output, estimated to be 2.5mn b/d, may only modestly increase to 2.6mbd by the end of 2017. According to Wells Fargo Securities and local newspapers in Midland, Texas, pipeline constraints in the Permian Basin will have already kicked in by the third quarter of 2017 given that much needed pipeline capacity will still be under construction.
4. E&P Companies capital expenditure reductions. By mid-2017 a number of North American E&P companies had announced downward revisions to their expected capital expenditure for 2017, some by as much as 14%. Such revisions, announced as part of their second-quarter earnings, reflected expectation that the price of WTI would remain around $45/b for the rest of 2017. As this has turned out not to be the case and based on renewed hedging activity in early August some of these cuts could be reversed.
5. Sanctions on Venezuelan crude oil. Venezuelan crude oils account for 10% of all American heavy crude imports and a wide network of refineries in the US South have been built to process these exact heavy grades. As 20 US refineries are fed with Venezuelan heavy crude and there appears to be no other source of supply for this type of oil in the oil market, sanctions on Venezuelan exports will impact on US refinery capacity and on the price of heavy crude oil and petroleum products particularly in the US. However, this unwanted side effect could be prevented by the US government if it in parallel with the implementation of sanctions against Venezuela acts decisively by filling the resulting gap with heavy crude oil grades released from the US Strategic Petroleum Reserve. It should be noted the US already has a program for the release of crude oil from strategic reserves. 
6. New oil production will likely come from new significant new oil finds in the US Gulf of Mexico, as well as from offshore Guiana and Mexico, where companies such as ExxonMobil and Eni and their respective partners are progressing field development without the security of previous $70-80/b forecasts. Vastly improved geological modelling has enabled better targeting drilling, even if the lack of local service industries and contractual requirements for local content may create obstacles along the way in Mexican field developments. 
7. Developments in Norway and the UK. A number of new oil production projects will come on stream on the UK and Norwegian continental shelfs in the period from end 2016 to the end of 2019, in total adding some 1.2mn b/d of new production. This will more than balance declining output from ageing fields in this offshore area, increasing total oil production by a net 400,000 b/d. Production technology innovations first implemented in the US, as well as sophisticated reservoir management techniques and aggressive cost cutting have revitalised offshore oil and gas production in Norway and the UK, making these industries viable at the current oil price environment.
8. Brazil further deep water exploration. Brazil and Petroleo Brasileiro S.A., better known as Petrobras is now selling licences and operatorships in offshore developments to foreign companies for further deep water exploration and production. This will likely lead to increased oil production from Brazil.
9. Russia’s ability to maintain or even further increase oil production. Last, but not least one should not underestimate Russia’s upstream industry. Despite the latest series of joint Russia/Saudi Arabia statements regarding new framework principles for longer term oil co-operation and price stabilisation new and enhanced developments of Russian oil production projects could be expected. However, the latest sanctions against Russia which the US is in the process of adopting will affect the Russian oil and gas industries. They target oil and gas projects in the Arctic; deep water; and shale formations; and possibly also new oil and gas export pipelines.

As for the demand-side developments, these are not to be underestimated either. Shell’s CEO Ben van Beurden could be right when he stated in a TV interview July 27 that oil demand could peak in ten years’ time.  This statement was underlined by his expressed decision that his next car will be electric. This gives a new meaning to this oil and gas major’s former marketing slogan: “Go well! Go Shell!” 

Given how many of the aforementioned factors are overlooked and/or misinterpreted, it is important for many oil industry market participants, particularly those aiming to profit from investments in oil based financial products, to carefully examine and understand the fundamentals and scenarios of the market they are or are likely to operate in. 

In the US the 2Q 2017 results from Chevron Corporation and ExxonMobil which both announced surprisingly strong profits for the quarter, are clear messages from the E&P side of the integrated international oil industry: the new world with WTI mainly in the $45-$50/b range, has been made to work for them. Both companies have large positions and increasing oil production in the Permian Basin. 

Turning to European based integrated oil companies: Shell, BP, ENI and Statoil all reported solid financial results and strong cash flows driven by good operational performances with high production efficiency and continued disciplined cost controls. This provides a clear and loud message: Crude oil at $50/b has again been made to work for the oil industry!

Low forever?

Equally important for the oil industry in particular, but also LNG and energy industries in general, are messages from a number of these international oil companies that low oil prices are not only here for longer, but more likely “for the future”, and that they already have adjusted their plans and strategies to face this reality. Projects must be able to withstand a low oil price, and new projects should not be developed in the belief that oil prices will increase in the future. This is another clear message.

In today’s LNG market a Brent blend crude price of $55/b translates into an LNG delivered ex-ship (DES) price of some $6.60/mn Btu based on a 12% slope. In the current soft LNG market medium term DES deals below 12% Brent slope have been concluded. This is not a comfortable price level for LNG project promoters and their bankers. This is why there are five US LNG export projects that have been given all necessary consents for construction and export, but have not yet started construction. These projects are: Lake Charles LNG, Magnolia LNG, an expansion at Cameron LNG and the sixth train at Sabin Pass, all in Louisiana, and Golden Pass LNG in Texas. These projects do not have the customer contracts required to support financing. To secure financing these projects are likely to need a DEC price for deliveries in Asia at some $7/mn Btu, if not above, secured under long term LNG supply agreements. LNG buyers in countries such as China are unlikely to accept such a price level when the LNG market is well supplied and spot prices for DES LNG deliveries to North East Asian markets, the destination-market price for this important LNG market region, fluctuate within a range of $4.00-$6.50/mn Btu for most of the year.

Turning again to WTI, since the US again became an exporter of crude oils to markets outside North America, that crude price has been between $1/b and $3.50/b below the price of Dated Brent. A Brent price of $55/b therefore translates into a WTI price of $51.50/b or more. At this WTI price level most US shale oil producers can operate economically, not only in the Permian Basin, but throughout the major shale plays in the lower 48 US states and Canada. Barring a major geopolitical upheaval, it is therefore unlikely the price of Brent blend will exceed $55/b soon; hence international oil companies have switched to face a reality of “low oil prices for the future”.   

Although Opec will now monitor members’ oil export levels as well as production, not all countries have followed the guidance: big questions under a “low oil prices for the future” scenario persist. These include the role that Opec can play in a long-term low oil price environment, if any; and how will the organisation’s oil income-dependent members be able to adjust to such a plausible development?

Answers to the above questions could prove troublesome for LNG liquefaction project promotors and their financers. A “low oil prices for the future” crude oil price environment will probably stop a number of planned LNG liquefaction projects and therefore bring forward the time when the LNG market again has a better balance between supply and demand.   

Morten Frisch is the senior partner of Morten Frisch Consulting (www.mfcgas.com).

Morten Frisch has analysed North American shale gas; shale/tight oil developments and their impact on LNG markets for over 15 years, following the 1998 breakthrough of the oil and gas company Mitchell Energy in commercial shale gas production in the Barnett field in Texas, after 18 years of pioneering work by the legendary Texas petroleum engineer and oilman George Mitchell. 

All views expressed in this article are the author’s own.  

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