Crude, which has fallen into a pattern of limited movements caught in a tug-of-war between evenly matched forces adding and subtracting supply, could be jolted by a hurricane in the US Gulf of Mexico, which was threatening major oil and gas production, refining, import andexport facilities Friday. As the market tracked the hurricane’s path towards Texas and waited to assess the short- and long-term impact of any damage and disruptions, crude was inching up, but gasoline futures had jumped, suggesting bigger worries over products supply. Meanwhile, a growing schism between Brent and WTI is paving the way for rising US crude exports — could that restore the traditional price relationships or is Brent's backwardation a precocious sign of the global oil market rebalancing?
Hurricane Harvey was barreling across the US Gulf of Mexico and towards the coast of Texas Thursday night local time, threatening major offshore oil and gas production and refining in the region, as well as imports and exports of crude and refined products.
Harvey was expected to make a landfall as a Category 3 hurricane Friday night or early Saturday local time and the US National Hurricane Center had warned of “life-threatening inundation from rising water moving inland from the coastline.”
The Gulf of Mexico offshore area pumps about 1.66 million b/d or 17% of the total US oil output. Some 8.44 million b/d or 46% of the country’s refining capacity is located in the Texas and Louisiana Gulf Coast districts.
Terminals in the region process around 3.9 million b/d of crude imports (46% of US total) and about 700,000 b/d of product imports (31%) an well as handling around 2.7 million b/d of finished petroleum product exports (82%).
Producers and refiners were scrambling to evacuate or shut down their facilities as a precautionary measure through Thursday night, while some continued to assess the situation, caught off-guard by the sudden strengthening of a storm that had disintegrated into a tropical depression as it crossed the Yucatan Peninsula earlier in the week.
The last major tropical cyclone to hit Texas was Hurricane Ike, close on the heels of Hurricane Gustav, both in September 2008. Those resulted in 1.3 million b/d of oil production and just over 7 Bcf/day of gas production in the US Gulf being shutin as a precautionary measure. About 85% of oil production and 71% of gas production had been restored in the 12 weeks after Gustav hit. Refining capacity outage peaked at 4 million b/d, but was fully restored in less than six weeks after Gustav.
Hurricanes Katrina and Rita in August and September 2005 respectively were far more destructive and caused longer outages. They shuttered up to 1.5 million b/d of oil and up to 8.8 Bcf/day of gas production. Restoration of supplies occurred gradually from November 2005 through March 2006. Twelve weeks after Katrina struck, a little over 5 Bcf/day of gas and over 1 million b/d of oil production was still shut in.
Beyond the knee-jerk rise in crude and product prices early Friday to factor in the likelihood of oil-related supply disruptions in general, Hurricane Harvey will need to be watched closely over the next 48 hours for a more detailed assessment of the precise nature and likely duration of its impact.
If the hurricane dissipates without causing any major damage to infrastructure and production and refining facilities, any capacity shut in as a precaution should be restarted fairly swiftly, enabling the crude market to return to “normal” within days. In the event of major damage to facilities, the impact could play out differently in the crude and refined products markets, depending on which infrastructure has suffered more.
A major, drawn-out oil production outage would support crude prices, but would also be mitigated by the presence of increased spare capacity available among the 22 OPEC and non-OPEC producers that have restrained supply under their agreements since January, as well as the cushion of brimming oil inventories globally.
If refineries in Texas are damaged and are forced to halt operations for a prolonged period, it would prop up refined product prices, while also pressuring crude down because of reduced demand for the feedstock, driving a rally in product cracks, or the premium of refined products over crude.
Any major disruptions in the imports and exports of crude and products will need to be analysed carefully, for they could well cancel each other out in terms of the balance between crude and refined product supply available in the country.
The market appeared more concerned about products than crude supply through the trading sessions in Asia and Europe Friday. The front-month September NYMEX RBOB gasoline contract changed hands at $1.7295/gal at 1300 GMT Friday, up 4% from Thursday’s settle, while WTI and Brent were up only 0.5% and 1% over the same period. The EIA Wednesday reported a 107,000 b/d rise in US gasoline demand to around 9.63 million b/d in the week to August 18, and a draw of 1.22 million barrels in gasoline stockpiles, supporting sentiment for the fuel amid the ongoing US summer driving demand season.
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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.
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
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:
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:
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.
Source: U.S. Energy Information Administration, Natural Gas Monthly