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Last Updated: January 4, 2018
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Market Watch

Headline crude prices for the week beginning 1 January 2017 – Brent: US$67/b; WTI: US$60/b

  • A combination of political unrest and strong demand pushed WTI past the US$60/b level for the first time since mid-2015.
  • Ongoing unrest in Iran, triggered by domestic grievances and anti-government sentiment that was responded to by an authoritarian crackdown, added to a bullish trend that began mid-December.
  • Repairs on the Forties Pipeline System has been fully completed, restoring supply in Europe and reducing some tightness in the market.
  • However, an outage at Libya’s pipeline to the Es Sider terminal - reportedly caused by insurgent activity – raised concerns of supply disruptions, with some reports suggesting Libya output had dropped by almost 1 mmb/d.
  • As 2018 begins, there are divergent opinions on how crude prices will develop. Moody’s Investors Services expects a range of US$40-60 on resurgent shale production, both others including JP Morgan and some bullish hedge funds believe prices could hit US$80/b.
  • Data from the US EIA showed American oil production declining to 9.75 mmb/d from 9.79 mmb/d, as output slowed over the Christmas break; production is expected to increase in the coming weeks, with many predicting output to top 10 mmb/d within Q118.
  • US commercial crude storage level dipped last week by 4.6 million barrels, down some 20% from historic highs hit in March 2017.
  • Active US rig sites fell by a net two to 777 last week; oil rig numbers were unchanged, with two gas rigs closing. Nonetheless, the US rig count was up by 222 sites y-o-y, from 525 over the last week of 2016.
  • Saudi Aramco is reportedly on the lookout to acquire natural gas assets and supplies internationally, while also developing local output, in a bid to reduce the amount of crude burnt for power over summer. This could unlock more supplies for export progressively over the next few years.
  • Crude price outlook: Optimism seems to be the flavour for the week. Supply disruption have abated, but there is geopolitical risk in Iran while oil demand seems healthy. Prices should stay in the US$66-67/b range for Brent, while WTI may dip back below US$60/b as US supply recovers after the Christmas/New Year break.


Headlines of the week

Upstream

  • The US has opened up the remote Arctic National Wildlife Refuge area in Alaska to oil and gas drilling as part of the recent Congress tax reform bill.
  • In the wake of this, Eni began drilling a new well near Alaska’s Oliktok Point in the Beaufort Sea – potentially yielding output of 20,000 b/d – which is the first well to be drilled in offshore north Alaska since 2015.
  • Indonesia has received bids - including from Repsol, Mubadala and KrisEnergy - for five oil and gas blocks it offered up in 2017, after two consecutive years of no interest. The 22 blocks previously offered over 2015 and 2016 will be put up for bids again this month.
  • Wintershall has started production at the Maria field in Norway a year ahead of schedule, with recoverable reserves of some 180 million boe.
  • Statoil has announced a NK19 billion (US$2.26 billion) plan to extend output at the Snorre field by some 200 million barrels, beginning 2021.
  • A new oil field came online in the UK in the last week of 2018, as Premier Oil’s Catcher field capped off a resurgent year for the North Sea. Catcher has an initial rate of 10 kb/d, rising to 60 kb/d by mid-2018.

Downstream

  • China has issued its first batch of crude import quotas for 2018. A total 121.32 million tons (2.43 mmb/d) has granted to 44 companies, with ChemChina having the largest share at 333 kb/d. Many independent teapot refiners saw substantial increases in their allocation.

Natural Gas/LNG

  • Algeria’s Sonatrach has inked a deal with BP and Statoil to produce an additional 11 bcm of natural gas from its Tiguentourine gas field, which has a current output of some 9 bcm/y since it started in 2006.
  • Rosneft has asked Russia’s competition watchdog to allow it to bid on natural gas fields in the Yamalo-Nenets region placed on sale by diamond mining firm Alrosa, pitting Rosneft against Novatek for the assets.
  • Qatargas and Austria’s OMV has agreed on a long-term LNG contract, delivering some 1.1 mtpa annually for five years, beginning January 2018.
  • China will launch a natural gas exchange in Chongqing in Q118, hoping to create an international price benchmark by combining pipeline imports from Central Asia/Russia and LNG imports. Chongqing will join Shanghai, Tokyo and Singapore in the race to create an Asian gas benchmark.
  • Gazprom has signed an MoU with Iran that will see it participate in the Iran LNG project, which has an initial plan for two trains of 5.25 mtpa each and a second stage that will double capacity.

Corporate

  • The public listing of ADNOC’s fuel distribution unit has been a major success. From an IPO price of DR2.50, trading opened at DR2.90 and remains above the launch price. The listing raised some US$851 million.

Rosneft has unveiled a five-year plan aimed at increase its crude oil output to 5 mmb/d and natural gas to 200 bcm by 2022.

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The US-China Trade Deal – What’s In It For The Energy Industry

The dust has settled after two years of tit-for-tat tariffs and incendiary accusations. At least for now. On 15th January 2020, the USA and China signed a landmark trade deal. Landmark because it extracts some concessions from China to redress the trade imbalance between the world’s two economic superpowers, and also because it halts the escalation of the trade war. Call it a trade truce, but the Phase 1 trade deal – as it has been called – also does not undo the previous two years of tariffs. In fact, it enshrines them at least until a Phase 2 deal is agreed.

But that’s very far away. For now, the headlines are all about the US getting China to buy almost US$200 billion more of US products over 2020 and 2021 across four key industries, in exchange for not raising tariffs on Chinese imports even further, including energy. Those are lofty promises. Verging on the unrealistic. But they make for great headlines, and good rhetoric for the White House. For energy, China has agreed to increase its buying of US energy products – including crude oil, LNG, refined products and coal – by US$18.5 billion in 2020 and US$33.9 billion in 2021, relative to the 2017 levels. That’s the promise. Can it be achieved?

Let’s take the base year. In 2017, the US exported some US$9 billion of energy products to China. On the oil side, this translated into 450,000 b/d of products – half of which was crude, another third was natural gas liquids (ethane and butane) and the remainder refined products. On the natural gas side, the US is estimated to have shipped 103 billion cubic feet of LNG to China in 2017. Across 2018 and 2019, exports of both oil and gas fell – and in the case of 2019, drastically as China slapped import tariffs of 5% on US crude and 25% on US LNG and NGLs. Which is why 2017 was chosen as the base year, representing a normal market before trade barriers kicked in. On a surface level, this would means that China would need to triple its purchases of US oil and gas to meet its Phase 1 trade pledges.

Is that realistic? US crude represented only 3% of Chinese crude imports in 2017, with LNG representing roughly the same portion. For LNG, China enjoys good relations with Australia, Qatar, Malaysia and Indonesia – all of which provide more competitive pricing given their proximity. For crude, it isn’t just volumes but also quality. Most Chinese refineries are designed around Middle Eastern and Russian crude – heavier and sourer than US crude. US crude could supplant existing volumes taken by China from West Africa and North Sea, but the Gulf of Mexico is once again at a distance disadvantage. A supply glut means China is awash with refined oil products, which leaves NGLs – which could be a bright spark as feedstock for Chinese petrochemicals producers. There is definitely room to grow, but expecting a tripling of volumes over two years seems highly unlikely unless strictly enforced.

Crucially, China has provided itself a safety clause. Buried in the text of the trade deal, is that these purchases – while representing minimum purchase requirements – are subject to ‘market conditions’ in China. These ‘market conditions’ are then further defined as being influenced by actual domestic Chinese demand, relative pricing of US goods vs comparable goods from other nations or supply availability, or all of the above. This crucial clause takes the purchase pledges by China from the realm of optimistic promises to fantasy. Emphasised throughout the trade deal document – and repeated again in the energy section – this essentially means that China’s pledge is not mandatory. China will continue to source its commodities based on ‘market conditions’ at the best availability and price; and if those suppliers happen to be American, good. US energy producers won’t be able to depend on a guaranteed deposit of demand from China – and they wouldn’t be able to produce all those required volumes anyway – but must continue to compete with established energy powerhouses like Russia, Saudi Arabia, Qatar, Australia, Iraq, Malaysia and more… just like they do now.

To expect China to be able to meet its pledges to increase US energy purchases by the required amounts is a fool’s game. Increases will happen, but even then, not by as much as expected given that the existing tariffs are still in place. The Phase 1 trade deal seems to be full of hot air.  It will make the negotiations for a broader Phase 2 trade deal tougher – given that progress on the targets will be expected – but that’s a question for the future, and possibly a different government. For now, not much has changed. Don’t call it a trade deal, call it what it is, which is a stalemate.

Phase 1 Trade Deal in Summary:

  • Chinese pledges in the Phase 1 US-China trade deal over 2020 and 2021*
  • Increase purchases of US manufactured goods by US$75 billion
  • Increase purchases of US agricultural goods by US$40 billion
  • Increase purchases of US services by US$35-40 billion
  • Increase purchases of US energy goods by US$52 billion
  • *All subject to prevailing ‘market conditions’
January, 29 2020
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