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Last Updated: August 3, 2018
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Market Watch

Headline crude prices for the week beginning 30 July 2018 – Brent: US$75/b; WTI: US$70/b

  • Supply concerns continue to weigh on global crude oil prices, but there is immediate relief on the horizon as production within OPEC rose by 70,000 b/d in July according to a Reuters survey – a high for 2018.
  • The WTI discount to Brent tightened as news filters out that the Syncrude facility outage in Canada may not be solved as quickly as hoped, which will translate to reduced oil flows in the Cushing, OK hub.
  • American numbers appear particularly tight, with US inventories near three-year lows last week and crude stocks at Cushing dropping to 23.7 million barrels, the lowest level since November 2014.
  • While supply continues to be a concern for 2018, the long-term supply outlook by analysts at Rystad Energy reveal that global discovered resources increased by 30% in 1H18, led by discoveries in Guyana, while oil majors are on pace to approve US$37 billion in upstream projects for the year.
  • Nevertheless, there is still the risk of disruption, with Total workers in the North Sea going on a 12-hour strike on July 30, while Saudi Arabia halted oil shipments in the Bab el-Mandeb Strait in the Red Sea as two of its tankers were attacked by Houthi militants from Yemen.
  • Wider concerns continue to hover too, as the US vacillates over its trade position, moving from negotiations to thaw relations with China over trade to threatening to up its tariffs from 10% to 25% on US$200 billion worth of Chinese imports currently under consideration by the administration.
  • US drillers, however, reversed three weeks of decline as three new oil rigs were started, offsetting a loss of one gas rig for a net gain of two.
  • Crude price outlook: Immediate supply concerns are ebbing as increased supply comes from OPEC+ countries, including Saudi Arabia, Russia and Iraq, but threat of disruptions and impending Iranian sanctions will keep prices in the US$72-75 range for Brent and the US$67-69 range for WTI.

Headlines of the week

Upstream

  • ExxonMobil has increased its estimate of recoverable resources from the Stabroek block offshore Guyana to more than 4 billion barrels of oil equivalent, up from 3.2 Bboe, while project costs are also expected to rise by a quarter given that the project might require up to 5 FPSOs.
  • The Kaombo offshore project, the largest in Angola, has started production, with Total’s Kaombo Norte FPSO unit brought onstream with a 115,000 b/d capacity, while the second FPSO Kaombo Sui is due next year.
  • BP has emerged as the winner of BHP Billiton’s onshore American assets, purchasing the latter’s interests in the Eagle Ford, Haynesville, Permian and Fayetteville oil and gas assets for US$10.8 billion.
  • Iran has become the second-largest supplier of oil to Indian state refiners in Q218, attracted by steep discounts as it stocks up before the sanctions kick in.
  • Total’s attempt to develop two oil blocks in South Sudan since 2013 has now been called off by the government, paving the way for other bidders to come in for the B1 and B2 blocks.
  • Mexican President-elect Andres Manuel Lopez Obrador has pledged to increase the country’s crude output from the current 1.9 mmb/d to 2.5 mmb/d, as well as revamp its existing six refineries and build a new one in Dos Bocas.
  • Russia is preparing the most sweeping shakeup of its oil tax system since 1999, which will allow producers to export crude and oil products duty free while raising wellhead costs in an attempt to revitalise the Russian economy.

Downstream

  • Not content with aiming for a B30 biodiesel mandate by 2019, Indonesia is now planning to implement its B20 across all gasoil sectors – including mining, marine, rail and non-subsidised diesel – as well as trialling a unique B100 palm oil-based ‘green diesel’ which could hit the market by 2022.
  • With PDVSA increasingly seen as unreliable, the Isla refinery in Curacao is speaking to at least 15 companies to temporarily operate the 335,000 bd Caribbean refinery, hoping to have one in place by September.
  • Algeria’s Sonatrach is reportedly looking to start up a trading joint venture, speaking with oil majors as it looks to purchase its first overseas refinery.
  • ExxonMobil has officially started production at its new ethane cracker in Baytown, Texas, part of its comprehensive ‘Growing the Gulf’ initiative.

Natural Gas/LNG

  • The US Energy Department has implemented faster approval of small-scale LNG and natural gas exports with an upper limit of 51.75 bcf/y of natural gas, targeting markets in the Caribbean, Central and South America.
  • Venice Energy, set up by former BHP Billiton executives, has joined two other proposed LNG import projects in East Australia, looking to fill a growing supply gap through an FSRU project in Port Adelaide by 2020.
  • Egypt is proving to be a hotbed of discoveries in 2018, with SDX Energy reporting a new gas discovery at the onshore SD-3X well in South Disouq.

Corporate

  • Russian petchems giant Sibur is preparing for an IPO that could potentially value the company at US$2-3 billion across bourses in Moscow and London.
  • Rosneft and ExxonMobil are heading for a legal clash, as the Russian behemoth is claiming US$1.41 billion in ‘unjust enrichment’ in Sakhalin-1.

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The Shale Showdown in 2020 – What’s Happening?

When asked in December about the projected slowdown in American shale output, the new US Energy Secretary shrugged off the notion, describing it as a mere ‘pause’. Blaming the expected slowdown to the ‘natural adjustments’ of oil and gas prices instead of a structural decline in production, Dan Brouilette is painting a rosy picture of US shale – where riches still lie underneath, waiting for the right price to be extracted. Of course he would paint such a picture. Brouilette is the new Energy Secretary, replacing Rick Perry. He couldn’t come in on a message of doom and gloom. But his pretty picture isn’t accurate either.

Schlumberger just posted a US$10 billion loss for the full year 2019, despite relatively flat y-o-y revenues. CEO Oliver Le Peuch called its international performance ‘positive’, but blamed ‘land market weakness’ causing a sharp decline in North American revenues and profits. Land market is code word for shale, and Schlumberger isn’t the only one facing problems. Halliburton announced a loss of US$1.1 billion in 2019, taking a US$2.2 billion charge on weakening US shale activity as North American revenue for Halliburton fell by 21% in 4Q19 and 18% for the whole year. While its results managed to beat analyst predictions – already stung by Schlumberger’s results – Halliburton doesn’t expect things to get rosier either, signalling that it expected ‘customer spending’ in North America to be down again in 2020.

And it isn’t just service companies suffering. US supermajor Chevron booked a US$11 billion write-down on a collection of assets in its latest set of financials, including on a major deepwater project in the Gulf of Mexico, the Kitimat LNG project in Canada and onshore Appalachian shale assets. Taken as a whole, the total impairment might coming from Chevron’s lowered forecast for oil and gas prices to the US$55-60/b range for 2020, but that shale was singled out is a major factor. And Chevron isn’t the only one. BP, Repsol and even ExxonMobil are expecting weakness. Only Shell and Total, who haven’t devoted as much attention to US shale, particularly the Permian, have been relatively insulated.  

Why is this happening? There are two different factors operating. From a producers’ standpoint, the rising tide of US shale output is contributing to weakening global prices  for oil – and that has a lot to do with the debt burden of existing US shale players, who have to keep drilling to pay off loans. Added conventional production coming online from Guyana, Brazil and Norway at the same time aren’t helping with prices either, despite OPEC+’s best intentions. From a service company’s perspective, firms like Schlumberger and Halliburton derive their revenue from drilling activity, not drilling output. And US drilling activity has dropped steeply over the past year, currently down by over 250 rigs according to the Baker Hughes weekly rig count. Much of this is onshore, principally in the Permian but also in other basins, as the once nimble and dynamic drillers are forced to stop activity either through bankruptcy or to shut shop temporarily as crude prices fall to uneconomical levels.

The US EIA has issued a new forecast, predicting that US shale output will slow down to a 1.1 mmb/d gain over 2020. That’s still optimistic, taking total US production to 13.3 mmb/d. In 2021, however, the EIA think output growth will fall even further, to an annual gain of just 400,000 b/d. Implicit to that forecast is that the EIA expects prices to remain subdued over the new two years, because shale drillers would respond to higher prices with increased drilling. There is also production structure to consider. Shale well produce immediate results, but show steep declines after. From 2012 to 2019, the amount of drilled but uncompleted (DUCs) wells – ie. wells that can be exploited within a short time frame – grew and grew; in the last 9 months, the glut of DUCs has shrunk – suggested that the industry is not drilling new wells as fast as they are completing already-drilled. Drilling activity has declined, and the chronic decline in the Baker Hughes active rig count – 18 of the last 21 weeks showed a net loss of rigs – is just proof of that.

It may not be the picture that Dan Brouilette wants to paint, but it is reality. The shale slowdown is real. It is also true that shale activity would increase if prices rose to more viable levels – say the US$65-70/b range – but let’s be honest, what are the odds of that happening when shale itself is the cause of weakening prices.

January, 28 2020
Flow Meter | Types Of Flow Meters From Nagmanflow

Nagman has diversified into dealing with Flow meters or Instruments viz Electro-Magnetic Flow Meters, Coriolis Mass Flow Meter, Positive Displacement Flow Meter, Vortex Flow Meter, Turbine Flow Meter, Ultrasonic Flow Meter.

Electro-Magnetic Flow Meter:
Size : DN 3 to DN 3000 mm
Flow Velocity : 0.5 m/s to 15 m/s
Accuracy : ±0.5%, ±0.2% of Reading

Coriolis Mass Flow Meter:
Size : DN8~DN300
Flow Range : 8 to 2500000 Kg/hr (for liquids)
4 to 2500000 Kg/hr (for gases)
Accuracy : 0.1% 0.2% 0.5% of Normal Flow Range

Positive Displacement Flow Meter:
Size : DN 15 ~ DN 400
Max. Flow Range : 0.3 m3/hr to 1800 m3/hr
(Will vary based on the measured media & temperature)
Accuracy : 0.1% 0.2% 0.5%

Vortex Flow Meter:
Size : DN 25 to DN 300
Flow Range : 1.3 m3/hr to 2000 m3/hr (Water)
8.0 m3/hr to 10000 m3/hr (Air)
Accuracy : ±1.0% of Reading

Turbine Flow Meter:
Size : DN 4 to DN 200
Flow Range : 0.02 m3 /hr to 680 m3 /hr
Accuracy : 1.0% or 0.5% of Rate

Ultrasonic Flow Meter:
Type : Hand held Ultrasonic Flow meter with S2, M2, L2 Sensors
Accuracy : ±1% of Reading at rates > 0.2 mps
Measuring Range : DN 15 – DN 6000


January, 24 2020
EIA expects U.S. net natural gas exports to almost double by 2021

In its Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts that U.S. natural gas exports will exceed natural gas imports by an average 7.3 billion cubic feet per day (Bcf/d) in 2020 (2.0 Bcf/d higher than in 2019) and 8.9 Bcf/d in 2021. Growth in U.S. net exports is led primarily by increases in liquefied natural gas (LNG) exports and pipeline exports to Mexico. Net natural gas exports more than doubled in 2019, compared with 2018, and EIA expects that they will almost double again by 2021 from 2019 levels.

The United States trades natural gas by pipeline with Canada and Mexico and as LNG with dozens of countries. Historically, the United States has imported more natural gas than it exports by pipeline from Canada. In contrast, the United States has been a net exporter of natural gas by pipeline to Mexico. The United States has been a net exporter of LNG since 2016 and delivers LNG to more than 30 countries.

In 2019, growth in demand for U.S. natural gas exports exceeded growth in natural gas consumption in the U.S. electric power sector. Natural gas deliveries to U.S. LNG export facilities and by pipeline to Mexico accounted for 12% of dry natural gas production in 2019. EIA forecasts these deliveries to account for an increasingly larger share through 2021 as new LNG facilities are placed in service and new pipelines in Mexico that connect to U.S. export pipelines begin operations.

Net U.S. natural gas imports from Canada have steadily declined in the past four years as new supplies from Appalachia into the Midwestern states have displaced some pipeline imports from Canada. U.S. pipeline exports to Canada have increased since 2018 when the NEXUS pipeline and Phase 2 of the Rover pipeline entered service. Overall, EIA projects the United States will remain a net natural gas importer from Canada through 2050.

U.S. pipeline exports to Mexico increased following expansions of cross-border pipeline capacity, averaging 5.1 Bcf/d from January through October 2019, 0.5 Bcf/d more than the 2018 annual average, according to EIA’s Natural Gas Monthly. The increase in exports was primarily the result of increased flows on the newly commissioned Sur de Texas–Tuxpan pipeline in Mexico, which transports natural gas from Texas to the southern Mexican state of Veracruz. Several new pipelines in Mexico that were scheduled to come online in 2019 were delayed are expected to enter service in 2020:

  • Pipelines in Central and Southwest Mexico (1.2 Bcf/d La Laguna–Aguascalientes and 0.9 Bcf/d Villa de Reyes–Aguascalientes–Guadalajara)
  • Pipelines in Western Mexico (0.5 Bcf/d Samalayuca–Sásabe)

U.S. LNG exports averaged 5 Bcf/d in 2019, 2 Bcf/d more than in 2018, as a result of several new facilities that placed their first trains in service. This year, several new liquefaction units (referred to as trains) are scheduled to be placed in service:

  • Trains 2 and 3 at Cameron LNG in Louisiana
  • Train 3 at Freeport LNG in Texas
  • Trains 5–10, six Moveable Modular Liquefaction System (MMLS) units, at Elba Island in Georgia

In 2021, the third train at the Corpus Christi facility in Texas is scheduled to come online, bringing the total U.S. liquefaction capacity to 10.2 Bcf/d (baseload) and 10.8 Bcf/d (peak). EIA expects LNG exports to continue to grow and average 6.5 Bcf/d in 2020 and 7.7 Bcf/d in 2021, as facilities gradually ramp up to full production.

monthly natural gas trade

Source: U.S. Energy Information Administration, Natural Gas Monthly

January, 24 2020