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Last Updated: August 7, 2017
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Last Week in World Oil:

Prices

  • Oil prices are showing some health, as US crude supplies seem to be moderating and the threat of renewed sanctions against Venezuela looms after a chaotic election there. Brent and WTI are clustering around the US$50/b mark, which seems to be the new support level, as signs are showing that US production may be shedding some optimism.

Upstream & Midstream

  • Shell has set out a schedule for eight upstream projects due for FID over the next 18 months, as it ramps up upstream investment that has been relatively stagnant since 2015. On the cards are the Bonga South West deepwater FPSO project in Nigeria and the Vito deepwater development in the US. The Val d’Agri onshore oilfield in Italy, Penguins FPSO in the UK and Libra FPSO in Brazil’s pre-salt Santos basin are also listed as potential oil projects. On the gas side, China’s Changbei 2 tight gas project and two LNG projects – Lake Charles in Louisiana and Canada LNG in Kitimat – are also being considered. Shell is looking to spend US$25 billion in 2017 on upstream capex, and a range of US$25-30 billion per year through 2020.
  • Pre-salt offshore production in Brazil has surpassed combined upstream output from all other fields for the first time. Output from Brazil’s pre-salt areas grew by 6.4% to 1.353 mmbpd in June, underpinning a 0.8% jump in production. The Lula field is the main pre-salt production area, at 763,000 bpd on average, with Petrobras remaining Brazil’s largest producer, ahead of Shell and Repsol Sinopec. Expect this trend to continue as Brazil attempts to stimulate investment in pre-salt basins by allowing more in more foreign competition to aid debt-stricken Petrobras.
  • Moderation in US drilling activity continues, with active oil rigs climbing only 2 to 766 last week. Six additional gas rigs were added, bringing the US total to 958, with signs pointing to active rig numbers plateauing as crude oil prices fail to break out from the stubborn US$50/b range.

Natural Gas and LNG

  • Output at Cheniere’s Sabine Pass LNG facility keeps marching upwards, with the company beginning liquefaction at a fourth plant ahead of the schedule. Sabine Pass’ fourth plant was scheduled to begin full service by end-2017, but appears to be starting up early in response to growing demand for Cheniere’s LNG, which is opening up new markets in Europe, Latin America and Asia. Officially commissioning for the fourth plant has yet to be completed, with output aimed at fulfilling a 20-year supply contract with GAIL India. The first three trains at Sabine Pass are contracted to Shell, Spain’s Gas Natural SDG and Korea Gas.
  • France’s highest court has repealed the country’s law on regulated gas, claiming that it flouted EU regulations. This might mean the end of regulated gas pricing in France, which would affect about half of French residential users and 11% of commercial users, weakening the entrenched position of energy group Engie and open up the market to smaller players like Direct Energy and foreign supplier like Italy’s Eni.

Last week in Asian oil

Upstream

  • Petronas has confirmed that it will be exiting Blocks 01 and 02 in Vietnam’s Cuu Long basin once the current PSC ends in early September 2017. Likely linked to declining output at the blocks, which began production in September 1991 as one of the first international ventures in Vietnam, Petronas stresses that the exit does not mean that it is quitting Vietnam, and will remain the operator of Blocks 102 and 106 in the Song Hong basin under Petronas Carigali.
  • China’s CNPC, together with partners Total, Petronas Carigali and Iraq’s South Oil Company, have sanctioned the Phase 3 Halfaya oilfield project in southern Iraq after approving FID. The project will boost production at the Maysan province field from a current 200,000 bpd to 400,000 bpd.
  • After backing joint drilling operations in areas claimed by both China and the Philippines, China is now calling for Vietnam to halt oil drilling in a section of the South China Sea claimed by both Vietnam and China. Drilling at Block 136/3, licensed to Repsol and Mubadala, began in mid-June, with China calling for an immediate halt to activities as it infringes on its territory. This may be posturing by the Chinese government to bring Vietnam to the table for joint oil exploration operations as in the Philippines, but Vietnam is unlikely to acquiesce the way Duterte has, which may lead to inflamed tensions in the South China Sea at a time when US foreign policy under President Trump is unclear.
  • Abu Dhabi’s Adnoc will make a decision on renewing the oil concessions held by Japanese companies in its oilfield by early next year, particularly Inpex’s 12% stake in the massive offshore ADMA block that is set to expire in March 2018. Japanese companies are keen to extend the contracts – key to securing strategic supplies for its refineries – while Abu Dhabi is leaning towards roping in new partners from China and South Korea, as well as expanding the role of majors BP and Total.

Downstream

  • The UAE has bought its first oil cargo from the USA, as it seeks to replace Qatari condensate affected by the current diplomatic row in the Middle East. Qatari supplies to the UAE – used in petrochemical production in the UAE – were halted in June after a Saudi Arabia-led campaign to politically isolate Qatar. Adnoc must now compete with condensate clients in South Korea and Japan to supplies of the ultra-light crude, with condensate from Eagle Ford being the most immediate source.

Natural Gas & LNG

  • Indonesia is aiming to begin constructing on an LNG pipeline system to establish a comprehensive gas distribution network across its vast archipelago. To be undertaken by state firms Pertamina, PGS and PLN, Indonesia will also need to attract international investment for a project that may cost as much as US$48 billion, part of a national plan to boost power generation and energy security in Indonesia.

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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.

April, 17 2019
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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