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Last Updated: September 15, 2017
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Last week in World oil:

Prices

  • Oil prices remained mixed at the start of this week, with Brent at US$53/b and WTI at US$48/b. The aftermath of Hurricane Irma hitting the Caribbean and Florida has stoked fears over demand, while there has been some delay in Texas refineries restarting post-Hurricane Harvey. Rumblings that Saudi Arabia and the UAE were pushing for a new extension in the OPEC supply cut agreement did provide some lift.

Upstream

  • Azerbaijan’s Socar is playing hardball as it negotiates new production sharing agreements with BP and the consortium for the Azeri-Ciraq-Gunashli oil fields. Originally signed in 1994, all parties want to extend it beyond expiration in 2024, but Azerbaijan is reported demanding its share to be increased to 20% from 11.6%. BP would be the major loser under this proposition, having its share reduced from 35.8% to 30%.
  • After gaining approval to move ahead with the Karish-Tanin natural field gas in Israel last week, Greece’s Energean Oil and Gas has also gained approval for Kataloko oil field in Western Greece. This will be Energean’s third project in the eastern Mediterranean, with a target of producing 11 million barrels of oil by 2020 and FID expected in 2018.
  • The rebalancing in Canadian heavy oil sector continues, as Canadian Natural Resources purchased Cenovus Energy’s Pelican Lake project in northern Alberta for US$788 million. Cenovus has been selling off assets acquired from ConocoPhillips in March to optimise its portfolio, allowing Canadian Natural to pick up its second major purchase this year, having bought Shell and Marathon Oil’s oil sands production for US$10.3 billion.
  • The US lost 3 oil rigs last week – the third fall in the past four weeks – although this was offset by a gain of 4 gas rigs, leading to a net gain of one.

Downstream & Midstream

  • Shell has joined the race for Mexico’s fuel retail sector, opening its first gas station last week as Pemex’s monopoly ends. The inaugural station is located in Mexico City, with Shell reporting that more will come as investments of up to US$1 billion are planned over the next decade.
  • Magellan Midstream Partners will be expanding its refined products pipeline system to handle emerging demand for gasoline, gasoil and jet fuel in Central and North Texas. A new 216-km pipeline will be build from Magellan’s terminal to Hearne, in partnership with Valero Energy, while an existing pipeline will be reversed and linked to the new segment.

Natural Gas and LNG

  • Angola will be selling LNG from its sole export facility to Vitol in its first long-term deal. Prior to this, Angolan LNG had been sold entirely via competitive tenders on the spot market, as concerns over plant reliability and consistent supply failed to create multi-year deals. Details of the agreement are confidential, but are part of a growing trend of traders securing long-term deals with producers to create a global LNG portfolio.

Corporate

  • Chinese conglomerate CEFC will buy a 14.16% stake in Russia’s Rosneft from Glencore and the Qatar Investment Authority for US$9.1 billion, boosting energy partnership between China and its largest supplier.

Last week in Asian oil

Upstream

  • The latest revisions to Indonesia’s new oil and gas production sharing contracts are seen as positive steps to attract investors. The latest tweaks keeps the government’s share at 52% for gas and 57% of oil production, but increase other components such as contractors’ share of output in the second and third stages of production or where assets have higher sulphur content. The Indonesian Petroleum Association described the revisions as ‘encouraging’, also praising the new tax incentives being drafted to make new energy contracts more attractive.

Natural Gas & LNG

  • India’s Reliance and BP have revived investment plans for the gas-rich NEC-OSN-97/2 block in the Bay of Bengal, within the offshore Mahanadi basin. Plans to develop the block were originally hindered by objections from the Defence Ministry due to its proximity to the Chandipur missile test base. These objections appeared to have been assuaged, and Reliance is now proceeding with development. This would be the second major project for Reliance and BP, which recently signed off on a US$6 billion plan to develop the Krishna-Godavari offshore basin, part of the India government’s plan to revive and boost domestic natural gas production.
  • BP has begun drilling its first shale gas well in the Neijiang-Dazhu block in China’s Sichuan basin, under a PSC with CNPC. This will be the first shale gas well to be drilled by a foreign major in China in several years, although CNPC is technically the block’s operator under the PSC terms. The block is one of two PSCs signed by BP with CNPC in the Sichuan basin, the other being Rongchangbei. Both blocks are understood to contain shale gas and conventional natural gas, but recent disappointments by Shell, Chevron and Hess in Sichuan and Guizhou may mean that the assets may not be commercially viable.
  • Australia’s Senex Energy will be developing a new gas field in the Surat Basin in Queensland, aiming to offer first gas to a tight local market by 2019. Senex gained the acreage for free on the condition that it be used to supply the Australian east coast market, and is next to Shell’s QGC acreage and close to existing gas pipeline infrastructure.
  • India’s Petronet LNG has announced a joint venture with Japanese and Sri Lankan partners to build an LNG terminal in Colombo. The plant is aimed at supplying gas to Sri Lanka’s power and transport sector, with initial design and capacity still under discussion. Completion is expected within two years of FID.
  • Western Australia has temporarily banned onshore hydraulic fracturing as it assesses environment risks associated. The state joins Victoria in banning fracking, with other Australian state also having moratoriums.

Corporate

  • Fresh of China’s acquisition of a stake in Rosneft by CEFC, Japan has also expressed interest in investing in energy companies, specifically citing Rosneft. The expressions of interest are by the Japan Oil, Gas and Metals National Corporation (JOGMEC), and can be seen as an attempt to not be left behind by China’s drive to acquire strategic stakes in key producers.

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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