East Timor and Australia are friends again. But a grudging friendship for mutual benefit that replaces the outright animosity that existed before. And like most fallouts, it revolved around money.
In 1974, the collective Greater Sunrise fields were discovered in the Timor Gap, an area of the Timor Sea that lies between Australia and then-Portuguese colony East Timor. With estimated reserves of some 5.13 tcf of natural gas – equivalent to about a third of current global LNG consumption – it is a jewel that is begging to be developed. However, Indonesia invaded East Timor – which had only enjoyed independence from Portugal for 9 days – and administered it until 2002; among the many things it conducted on ‘behalf’ of the Timorese was to agree on a maritime border with Australia.
As it finally became independent in 2002, the new East Timor (Democratic Republic of Timor-Leste) needed new friends. Indonesia wasn’t the best option, so it turned to Australia, its largest international supporter. But the riches in the Timor Sea proved too vast. Although the young and naïve East Timor did agree on treaties governing joint development of the Timor Gap and Greater Sunrise, it also asserted that it did not recognise the maritime border agreed by Indonesia with Australia. Rather, it argued for a border that is equi-distance between East Timor and Australia; a move that would put Greater Sunrise within Timorese waters. Alarmed by this, Australia’s government sanctioned placing bugs within the Timorese cabinets to monitor discussions. And just as Greater Sunrise was on the verge of finally being developed, the scandal broke… followed by years of argument and accusations.
That has been put aside for now. East Timor dropped its suit against Australia at the Permanent Court of Arbitration last year, and last week signed a new treaty that redraws their maritime boundary*. This formally ends the dispute over the border. It, however, does not set out terms of the actual field development, preferring to leave that up to the Greater Sunrise consortium of Woodside, ConocoPhillips, Shell and Osaka Gas – East Timor will receive at least 70% of Greater Sunrise revenues, up to 80% depending on where the gas is processed. The decision is particularly pertinent for East Timor, as its Bayu Undan field – the only major gas production field in operation – is set to be depleted by 2022. From friends to enemies to friends again, Australia has sought to re-assure all parties that no clandestine shenanigans were involved this time.
*On 6 March 2018, Australia’s Minister for Foreign Affairs, the Hon Julie Bishop MP, and Timor-Leste’s Minister in the Office of the Prime Minister for the Delimitation of Borders and the Agent in the Conciliation, His Excellency Mr Hermenegildo Pereira, signed the Treaty Between Australia and the Democratic Republic of Timor-Leste Establishing Their Maritime Boundaries in the Timor Sea [PDF 592 KB]. The treaty was signed in New York at the United Nations Headquarters in the presence of the United Nations Secretary-General and the Chair of the Conciliation Commission.
"Frenemy" (less commonly spelled "frienemy") is an oxymoron and a portmanteau of "friend" and "enemy" that refers to "a person with whom one is friendly, despite a fundamental dislike or rivalry" or "a person who combines the characteristics of a friend and an enemy". https://en.wikipedia.org/wiki/Frenemy
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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