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Last Updated: December 21, 2017
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Market Watch

Headline crude prices for the week beginning 18 December 2017 – Brent: US$63/b; WTI: US$57/b

  • Suspension of a planned strike of Nigeria’s Pengassan oil union eased prices back, although talks deferred to January could still break down.
  • The hairline crack that prompted the shutdown of the Forties Pipeline System has not propagated, and repairs should be completed by the New Year, also easing speculative pressure on prices.
  • OPEC announced that it expects the market to be balanced by late 2018, underscoring that there will be no more extensions to its current supply deal.
  • The US EIA sees crude output at major American shale plays reaching 6.41 mmb/d a day in January
  • American domestic oil inventories slid by 5.2 million barrels last week, exceeding a forecast of 3.15 million barrels – an indication of healthy demand even with rising supply.
  • Active US rig sites fell by a net one last week; loss of 4 oil rigs offset a 3-site gain in gas rigs. Canadian rig count jumped by 19, all oil additions.
  • European gas prices spiked up after fire broke out at the Baumgarten gas hub in Austria, after jumping on the closure of the UK Forties pipeline system. Asian LNG spot prices followed suit, jumping to US$10.50 mmBtu for January deliveries.
  • Saudi Arabia will raise its capital spending to US$414 billion through 2027. Some US$134 billion will be spent on drilling/well services, US$78 billion on maintaining reserves and the remainder focused on expanding infrastructure and new businesses.
  • Crude price outlook: As supply threats abate and the market prepares for the long year-end break, no dramatic movement is expected in prices. Prices should drift down to US$62/b for Brent and US$56/b for WTI – a good way to start 2018.


Headlines of the week

Upstream

  • Repairs at the Forties Pipeline System is expected to take up to four weeks to complete, as Ineos declared force majeure on Forties deliveries.
  • Aker BP has unveiled plans to spend US$1 billion to develop the Ærfugl, Valhall Flank West and Skogul fields in Norway.
  • Interest in the UK North Sea continues with a new player on the scene – Spirit Energy, a joint venture between Centrica and Bayerngas Norge.
  • Lebanon has approved a consortium formed by Total, Eni and Russia’s Novatek to begin exploring for oil and gas in its waters, where the country hopes to extend the streak of big eastern Mediterranean discoveries.
  • ADNOC has been polling its Asian buyers on whether it should maintain its current system of retroactive pricing, or change to forward pricing as part of a major review of Abu Dhabi’s monthly crude pricing mechanism.
  • Fresh off its onshore success Uganda and Kenya, Tullow Oil is now adding South Sudan as a market of interest, owing to similar geology.

Downstream

  • A new processing unit has been added to Iraq’s Kirkuk refinery, increasing capacity to 56 kb/d, part of a push to have more Kirkuk crude processed locally instead of exported by pipeline.
  • PDVSA’s woes means that it is losing grip on a refining system created in its own backyard, pulling out of the Cienfuegos refinery in Cuba. PDVSA’s 49% stake in Cienfuegos, supplied by Venezuelan crude, has been transferred to the Cuban government as debt settlement.
  • BP is emerging as one of the early leaders in Mexico’s deregulated downstream, opening its 100th retail station last week and on target to achieve a network of 500 by the end of 2018.

Natural Gas/LNG

  • First gas has been produced from Eni’s Zohr field in Egypt less than two and a half years after discovery, transforming Egypt from a hungry net importer to a potentially powerful exporter.
  • After acquiring a 25% stake in the gas-rich Area 4 block in Mozambique from Eni, ExxonMobil confirms that it will now lead midstream operations and all liquefaction (plus related) facilities at Area 4. Eni, in return, will take the lead on all upstream operations and Coral FLNG.
  • Indonesia is aiming to sign off on final development of the Abadi LNG project in mid-2018, pushing for a start-up as early as 2023.
  • Rosneft has gained the licences to develop two major offshore gas fields in the country. With total reserves of 180 bcm, Rosneft holds the Patao and Mejillones licences for the next 30 years.

Corporate

Petrobras and ExxonMobil has formed a strategic alliance, aimed to cooperating on global energy projects across exploration, production and chemicals.

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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