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Last Updated: March 15, 2017
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Last Week in World Oil:

Prices

  • With US drilling rising and crude inventories soaring, WTI crude oil has slipped underneath the US$50/b psychological barrier, with Brent not far behind at US$51/b. Some OPEC producers already calling for an extension of the six-month output freeze, but all that will do is stabilise prices.

Upstream & Midstream

  • Shell will be withdrawing almost entirely from Canadian oil sands, an acknowledgement that expensive projects are non-starters in the current price environment. It will sell its existing and undeveloped oil sands interest to Canadian Natural for US$8.5 billion – going a long way to reducing its debt from acquiring BG – and will also reduce its share in the Athabasca Oil Sand Project from 60% to 10%. The net gain for Shell will be US$7.25 billion, as it has also purchased half of Marathon Oil Canada.
  • In other Shell news, the supermajor is reluctant to reopen the Trans Forcados pipeline in Nigeria, leaving the 400 kb/d Forcados export terminal idle, fearing new attacks by militants. Though attacks by the Niger Delta Avengers have lessened, Shell is demanding additional protection from a government desperate to bring nearly 500 kb/d of offline capacity back. The pipeline was bombed twice last year, the second time just 48 hours after seven months of repairs were completed.
  • Eight new oil rigs were activated last week, joining five new gas rigs to bring the US active rig count to 768, the eight consecutive weekly rise.

Downstream

  • The liberalisation of the Mexican fuel retail industry, breaking the Pemex monopoly and introducing price reforms, has downstream companies buzzing. The biggest of these is BP, which is planning to open up some 1,500 service stations over the next five years, another sign that the British supermajor may be warming back to the idea of downstream retailing after years of focusing on upstream. And it isn’t the only big player interested; trader Glencore is also mulling a move into Mexican retail, investing over US$200 million in a 15-year supply deal.
  • Austria’s OMV is selling its Turkish fuel supply and distribution unit Petro Ofisi to Vitol for US$1.45 billion, as it moves to shed non-core assets, particularly in the low-margin Turkish market. Current political tensions between Turkey and the EU may have also contributed to the sale.

Natural Gas and LNG

  • Russia’s Gazprom has announced a round of delays for its LNG projects, pushing the Sakhalin-2 project from 2021 to 2023/4, and the Baltic LNG plant in Leningrad from 2021 to 2022/3. The delays could leave Russia behind Canada, Australia and the US in the race to supply LNG-hungry Asia, and behind its target to triple its current market share by 2035.

Corporate

  • As Saudi Aramco tidies up its vast holdings – including its split with Shell over the Motiva Enterprises venture in the US – fund managers and institutional investors are expecting it to achieve a market capitalisation of up to US$1.5 trillion in its planned IPO, which would instantly make it the most valuable public company in the world.


Last Week in Asian Oil:

Upstream & Midstream

  • The sale of Chevron’s Bangladesh natural gas assets may be attracting  friction between the government and China. After a request to hike gas prices failed in 2015, the US supermajor put its assets – which account for roughly 60% of Bangladesh’s production from the onshore Bibiyana, Jalalabad and Moulavi Bazar fields – up for sale and cancelled a planned US$650 million investment. State-owned Petrobangla has first refusal, but China’s Zenhua Oil is also in the running, pricing the assets at about US$2 billion. Zhenhua is an arm of China’s NORINCO, a state-run defence industry player, and is one of the minor energy players stepping out of the Sinopec and PetroChina shadows to assert China’s influence globally.
  • Myanmar has given the go-ahead on the MD-7 project, which will see French major Total purchase a 50% interest in the offshore deepwater block from Thailand’s PTTEP. PTTEP has traditionally been the major upstream player in Myanmar, a holdover from the days when the country was considered a pariah nation, and has an on-going collaboration with Total that stretches back 30 years.  
  • Spain’s Repsol sold its 50% interest in the Indonesian Ogan Komering PSC (Production Sharing Contract) to local player Jadestone Energy. The tiny South Sumatran block, producing an average of 3 kb/d, is seen by Jadestone as key in expanding its Indonesia presence. Pertamina retains the other 50%, with Repsol seemingly more interested in the discovery it made in Alaska’s North Slope, the largest conventional onshore discovery in the US for over 30 years.

Downstream & Shipping

  • Two months after a setting a monthly crude import record, February 2017 crude imports reached China’s second-highest level, despite the shorter month. Volumes entering China rose to 8.286 mmb/d, with the demand from independent teapots driving the rise. Imports should ease over the next few months, as some major refineries enter maintenance periods, but the strong teapot demand may keep imports high.

Natural Gas & LNG

  • Malaysia’s Petronas has inked a new LNG deal, the third signed so far this year with the client once again being Japanese. The contract will send some 130,000 tons of LNG per year to the Hokkaido Electric Power Company over a 10 years, supplied from the Bintulu LNG complex.
  • BP’s Tangguh Train 2 in Indonesia’s West Papua will be shut down for nearly two months beginning early April. The routine maintenance should not affect the Tangguh LNG’s production plan for the year, which include 63 uncommitted cargoes. Tangguh Train 1 will remain operational.

Corporate

  • There might be a new name in China to watch. With ambitions of becoming the‘second Sinopec’, private Chinese conglomerate CEFC China Energy has already bought a 4% stake in an Abu Dhabi oilfield for US$900 million and has approached several large independent teapots in Shandong with an idea to acquire its first domestic refinery operation. It is the first example of a large private firm attempting to break into the ranks of Chinese energy majors, a motivation encouraged by Beijing as it seeks to foster competition in the domestic market. CEFC already owns a refinery in Romania, a network of service stations in Europe and an oilfield in Chad, all acquired on the quiet in just two years.

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In 2018, the United States consumed more energy than ever before

U.S. total energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Primary energy consumption in the United States reached a record high of 101.3 quadrillion British thermal units (Btu) in 2018, up 4% from 2017 and 0.3% above the previous record set in 2007. The increase in 2018 was the largest increase in energy consumption, in both absolute and percentage terms, since 2010.

Consumption of fossil fuels—petroleum, natural gas, and coal—grew by 4% in 2018 and accounted for 80% of U.S. total energy consumption. Natural gas consumption reached a record high, rising by 10% from 2017. This increase in natural gas, along with relatively smaller increases in the consumption of petroleum fuels, renewable energy, and nuclear electric power, more than offset a 4% decline in coal consumption.

U.S. total energy consumption

Source: U.S. Energy Information Administration, Monthly Energy Review

Petroleum consumption in the United States increased to 20.5 million barrels per day (b/d), or 37 quadrillion Btu in 2018, up nearly 500,000 b/d from 2017 and the highest level since 2007. Growth was driven primarily by increased use in the industrial sector, which grew by about 200,000 b/d in 2018. The transportation sector grew by about 140,000 b/d in 2018 as a result of increased demand for fuels such as petroleum diesel and jet fuel.

Natural gas consumption in the United States reached a record high 83.1 billion cubic feet/day (Bcf/d), the equivalent of 31 quadrillion Btu, in 2018. Natural gas use rose across all sectors in 2018, primarily driven by weather-related factors that increased demand for space heating during the winter and for air conditioning during the summer. As more natural gas-fired power plants came online and existing natural gas-fired power plants were used more often, natural gas consumption in the electric power sector increased 15% from 2017 levels to 29.1 Bcf/d. Natural gas consumption also grew in the residential, commercial, and industrial sectors in 2018, increasing 13%, 10%, and 4% compared with 2017 levels, respectively.

Coal consumption in the United States fell to 688 million short tons (13 quadrillion Btu) in 2018, the fifth consecutive year of decline. Almost all of the reduction came from the electric power sector, which fell 4% from 2017 levels. Coal-fired power plants continued to be displaced by newer, more efficient natural gas and renewable power generation sources. In 2018, 12.9 gigawatts (GW) of coal-fired capacity were retired, while 14.6 GW of net natural gas-fired capacity were added.

U.S. fossil fuel energy consumption by sector

Source: U.S. Energy Information Administration, Monthly Energy Review

Renewable energy consumption in the United States reached a record high 11.5 quadrillion Btu in 2018, rising 3% from 2017, largely driven by the addition of new wind and solar power plants. Wind electricity consumption increased by 8% while solar consumption rose 22%. Biomass consumption, primarily in the form of transportation fuels such as fuel ethanol and biodiesel, accounted for 45% of all renewable consumption in 2018, up 1% from 2017 levels. Increases in wind, solar, and biomass consumption were partially offset by a 3% decrease in hydroelectricity consumption.

U.S. energy consumption of selected fuels

Source: U.S. Energy Information Administration, Monthly Energy Review

Nuclear consumption in the United States increased less than 1% compared with 2017 levels but still set a record for electricity generation in 2018. The number of total operable nuclear generating units decreased to 98 in September 2018 when the Oyster Creek Nuclear Generating Station in New Jersey was retired. Annual average nuclear capacity factors, which reflect the use of power plants, were slightly higher at 92.6% in 2018 compared with 92.2% in 2017.

More information about total energy consumption, production, trade, and emissions is available in EIA’s Monthly Energy Review.

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April, 17 2019
A New Frontier for LNG Pricing and Contracts

How’s this for a first? As the world’s demand for LNG continues to grow, the world’s largest LNG supplier (Shell) has inked an innovative new deal with one of the world’s largest LNG buyers (Tokyo Gas), including a coal pricing formula link for the first time in a large-scale LNG contract. It’s a notable change in an industry that has long depended on pricing gas off crude, but could this be a sign of new things to come?

Both parties have named the deal an ‘innovative solution’, with Tokyo Gas hailing it as a ‘further diversification of price indexation’ and Shell calling it a ‘tailored solutions including flexible contract terms under a variety of pricing indices.’ Beneath the rhetoric, the actual nuts and bolts is slightly more mundane. The pricing formula link to coal indexation will only be used for part of the supply, with the remainder priced off the conventional oil & gas-linked indexation ie. Brent and Henry Hub pricing. This makes sense, since Tokyo Gas will be sourcing LNG from Shell’s global portfolio – which includes upcoming projects in Canada and the US Gulf Coast. Neither party provided the split of volumes under each pricing method, meaning that the coal-linked portion could be small, acting as a hedge.

However, it is likely that the push for this came from Tokyo Gas. As one of the world’s largest LNG buyers, Tokyo Gas has been at the forefront of redefining the strict traditions of LNG contracts. Reading between the lines, this deal most likely does not include any destination restriction clauses, a change that Tokyo Gas has been particularly pushing for. With the trajectory for Brent crude prices uncertain – owing to a difficult-to-predict balance between OPEC+ and US shale – creating a third link in the pricing formula might be a good move. Particularly since in Japan, LNG faces off directly with coal in power generation. With the general retreat from nuclear power in the country, the coal-LNG battle will intensify.

What does this mean for the rest of the industry? Could coal-linked contracts become the norm? The industry has been discussing new innovations in LNG contracts at the recent LNG2019 conference in Shanghai, while the influx of new American LNG players hungry to seal deals has unleashed a new sense of flexibility. But will there be takers?

I am not a pricing expert but the answer is maybe. While Tokyo Gas predominantly uses natural gas as its power generation fuel (hence the name), it is competing with other players using cheaper coal-based generation. So in Japan, LNG and coal are direct competitors. This is also true in South Korea and much of Southeast Asia. In the two rising Asian LNG powerhouses, however, the situation is different. In China – on track to become the world’s largest LNG buyer in the next two decades – LNG is rarely used in power generation, consumed instead by residential heating. In India – where LNG imports are also rising sharply – LNG is primarily aimed at petrochemicals and fertiliser. LNG based power generation in China and India could see a surge, of course, but that will take plenty of infrastructure, and time, to build. It is far more likely that their contracts will be based off existing LNG or natural gas benchmarks, several of which are being developed in Asia alone.

If it takes off  the coal-link LNG formula is likely to remain a Asian-based development. But with the huge volumes demanded by countries in this region, that’s still a very big niche. Enough perhaps for the innovation to slowly gain traction elsewhere, next stop -  Europe?

The Shell-Tokyo Gas Deal:

Contract – April 2020-March 2030 (10 Years)

Volume – 500,000 metric tons per year

Source – Shell global portfolio

Pricing – Formula based on coal and oil & gas-linked indexes

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April, 15 2019