Easwaran Kanason

Co - founder of PetroEdge
Last Updated: November 15, 2016
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Business Trends
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Last week in world oil:

Oil markets have largely shrugged off the victory of Donald Trump in the US presidential elections and instead focused on tangible numbers – that OPEC output rose in September, with a 200 kb/d leap in Iran alone. With oversupply on the market, and the likelihood of a supply freeze slim, prices are now in the US$43-44/b range. 

The opening of the Brazil’s upstream industry is opportunity enough for Shell to commit US$10 billion towards over the next five years. Although it has been shying away from investment elsewhere, Brazil is enough of a jewel to warrant funding, with Shell particularly interest in the country’s vast offshore subsalt reserves, which will be opened up to foreign investment after being previously monopolised by Petrobras. 

Another week and the operating US oil rig count have risen again, up by 2 to 452 sites, although the pace of expansion has slowed down markedly. The gas rig count fell by 2, leaving the total number unchanged 

China’s Guangdong Zhenrong Energy has signed an agreement with the UK’s BP on supply and offtake at the Isla refinery in Curacao, once the Chinese commodity trader completes its takeover and planned upgrade of the aging refinery. Under the terms of the agreement, BP will supply crude to the 335 kb/d refinery, currently leased by Venezuela’s PDVSA, and take all of the refined products produced, which will be marketed in the Americas. PDVSA will likely not be sidelined completely; it remains the most logical, and closest, crude oil supplier to the site. 

Mexico’s national oil company PEMEX is aiming to establish a network of partners that help it reconfigure and upgrade its refinery network in the country, which is ailing and inefficiently. The Bank of America has been hired to lead Pemex’s search for joint ventures to upgrade the Tula, Salamanca and Salina Cruz refineries. Priority will be given to the Tula refinery’s aging coking unit, currently operating at minimum levels, contributing to disappointing national output in September, at less than 50% of the total Mexican refinery capacity. 

France’s Total has signed the first post-sanction deal by a western energy company in Iran, confirming its participation in the South Pars Phase 11 development with NIOC in the world’s largest natural gas field. The field, which extends in Qatari waters as the North Field, will cost US$2 billion to develop, with the gas earmarked for Iran’s gas and power grid. Total was heavily involved in Phases 2 and 3 of South Pars in the 2000s, but exited in 2010 after sanctions was slapped over Iran’s nuclear programme. 

Nigeria is aiming to overhaul its state oil company NNPC from a lumbering, bureaucratic behemoth into a modern, streamlined company to minimise graft and mismanagement. Possibly using Malaysia’s Petronas as a blueprint, the goal is to eventually list NNPC on the stock exchange and separate the cumbersome regulatory and policy tasks it is currently responsible for to focus entirely on commercial activity. 

After hitting a record high in September, Chinese crude oil imports fell to its lowest level since January this year as independent teapot refiners cut back on purchases over higher crude prices and dwindling import quotas. Imports are still significantly higher on annual basis, but it appears that the teapots’ ravenous appetite for processing over summer have left them with little room to import as the country moves into winter heating mode. 

With Chevron looking to exit the upstream industry in Bangladesh, the country’s government is aiming to keep Chevron’s assets – which include three gas productions fields (Jalalabad, Moulavi and Bibiyana) with a collective output of 720 million cubic feet a day – in its own hands by directing state-owned Petrobangla to acquire them. With a value of US$2-3 billion, the government is hoping to settle for a price of US$1.5 billion.

Oman Oil Company is switching partners for its Duqm refinery from Abu Dhabi’s International Petroleum Investment Co to Kuwait Petroleum Corporation after it failed to reach an agreement with the former. The 230 kb/d Duqm refinery is part of a massive industrial zone meant to diversify Oman’s economy away from upstream oil. Under the new partnership, Duqm will now process a mix of Omani and Kuwaiti crude. 

While Australia is on course to become the world’s top exporter of LNG, the status pulls natural gas supply in the sparsely-populated west away from the main population centres in the east. This creates a hole in east Australia which may have to be plugged by imports, as AGL Energy considers building a LNG terminal somewhere along the country’s southeast coast by 2021. Currently, domestic gas supply in the southeast is dominated by ExxonMobil, BHP Biliton, Origin Energy and Santos, which hiked up prices in July almost sixfold during a winter cold snap.

The Japanese parliament has passed a bill that will allow the state-run Japan Oil, Gas and Metals National Corp (JOGMEC) to participate on foreign acquisitions. Previously restricted to purchases of foreign natural gas assets, the change in the law allows JOGMEC to work with Japanese firms, or on its own, in acquiring foreign state or private firms, as the government seeks to expand the financial muscle for Japanese companies in the race with China and India to acquire energy assets. 

Chevron has been slapped with a US$200 million tax bill by the Thai government over shipments of oil to its offshore facilities in the Gulf of Thailand. The issue centres on the interpretation of customs legislations; Chevron believes that the law classifies shipments of oil exceeding the 12 nautical mile limit to be exports and therefore exempt from customs duties. However, the Customs department believes that since the destination falls within Thai waters, it should be subject to excise tax, oil fund levy and a 7% VAT, backdated to 2001. Discussion between Chevron and the Thai government continue over the issue. 

Have a productive week ahead!

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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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