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Last Updated: May 3, 2019
Business Trends

Market Watch

Headline crude prices for the week beginning 29 April 2019 – Brent: US$72/b; WTI: US$63/b

  • After touching fresh peaks the previous week, as the USA confirmed its intention to hold firm to its decision to end waivers on Iranian crude, global crude oil prices have taken a bit of a breather, easing back as the Americans vowed to make up for the loss of Iranian crude volumes
  • Iran itself has threatened to close the Strait of Hormuz – a threat it has used in the past – stating that ‘if we are prevented from using it, we will close it’, a direct threat to the US’ return to aggressive sanctions designed to reduce Iranian oil export ‘to zero’
  • With Saudi Arabia and Russia appearing poised to make up for the Iranian loss, the market also noted that President Donald Trump was once again calling on OPEC to reduce oil prices, despite being responsible for causing it in the first place
  • Meanwhile in strife-set Venezuela, crude oil production fell to 840,000 b/d in March, the lowest level for the country since January 2003; renewed tensions between pro-Maduro and pro-Guaido forces in the country could lead to a possible civil war, further hampering output
  • The active US rig count fell by a huge 21 sites last week – 20 oil and 1 gas – bringing the total rig count below the 1000 level for the first time in 15 months to 991 sites with most of the losses in onshore shale basins
  • Crude oil is like to fall back to the US$70-72/b range for Brent and US$61-63/b for WTI, with reports of ample supplies in the market washing over concerns of the end of Iranian crude waivers and the continued implosion in Iran

Headlines of the week


  • The Chevron-Anadarko deal is not yet set in stone, with rival Occidental Petroleum engaging in a bidding war with a new US$38 billion takeover proposal – or a 20% premium over Chevron’s offer
  • Shell claims that it has made a ‘blockbuster’ discovery at its Blacktip deepwater well in the Gulf of Mexico, with the Perdido Corridor asset shared with Chevron, Equinor and Respsol reporting ‘significant’ oil flows
  • Lukoil has achieved cumulative production of 100 million tons at Iraq’s West-Qurna-2 field over Phase 1 of the project, with current output of 400,000 b/d
  • CNOOC and PetroChina have signed a new Petroleum Contract, covering the Beibu Gulf 23/29 and Beibu Gulf 24/11 blocks in the South China Sea
  • ExxonMobil will be adding some 28,000 to its exploration acreage in Namibia through the addition of offshore Blocks 1710 and 1810 and farm-in agreements with state firm NAMCOR for Blocks 1711 and 1811A
  • The Trump administration will be delaying its plans to vastly open up federal coastal waters for oil and gas drilling until after 2020 Presidential election, following legal setbacks and opposition from coastal Republicans
  • ADNOC has launched a second licensing round in Abu Dhabi, covering the offshore Block 3, 4 and 5, and the onshore Blocks 2 and 5
  • Angola is reportedly planning to offer nine oil blocks in the prolific Namibe basin for auction this year to capitalise on a swell in crude prices

Midstream & Downstream

  • ExxonMobil will be expanding its 270 kb/d Fawley refinery in the UK to increase ultra-low sulfur diesel output by 38 kb/d, the latest in a string of clean fuel investments across the supermajor global refining network
  • Azerbaijan’s new STAR refinery in Turkey will be expanding its crude diet away from the current source of Russian Urals crude to include other Middle Eastern and African grades beginning this month
  • Indian Oil’s 160 kb/d Mathura refinery in northern state Uttar Pradesh will be shut down for over a month beginning November 2019 for full maintenance
  • Shell employees at the 400 kb/d Pernis refinery in the Netherlands have voted to end a union-backed strike after a new wage offer was made by Shell
  • As rumoured, Saudi Aramco has bought out Shell’s 50% stake in the Jubail Industrial City SASREF refining joint venture for US$631 million

Natural Gas/LNG

  • Saudi Aramco has sold its first shipment of LNG ever – despite not producing a single drop of the fuel – with the trade coming out of its Singapore trading arm to an unidentified Indian buyer
  • ExxonMobil and China’s Zhejiang Provincial Energy Group have signed a sales agreement for the 20-year supply of 1 mtpa of LNG beginning 2021
  • China’s CNOOC has reached an agreement with Russia’s Novatek to acquire a 10% interest in the Arctic LNG-2 project located on the Gydan Peninsula
  • President Donald Trump is reportedly considering waiving a requirement that only US-flagged ships can move natural gas between two US ports, to ease distribution and bottlenecks within the US natural gas system
  • Australia’s Santos has acquired all remaining equity in the Tern and Frigate gas discoveries in Australia, boosting its position in the growing LNG space there
  • China is reportedly looking into a plan to build a network of LNG plants along the Yangtze river to improve supplies to underdeveloped areas upstream

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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