In 2005, the tiny Persian Gulf nation of Qatar declared a moratorium on production at its North Field. Natural gas from this giant field, part of a larger reservoir that straddles Qatari and Iranian borders, had helped Qatar ramp up production, eight years after it exported its first cargo of LNG to Spain in 1997. The halt came as a bit of a surprise back then, seen as limiting, but in hindsight was a great move. Existing projects with partners ExxonMobil, Shell and Total were more than enough to vault Qatar to become the largest LNG exporter in the world, and there were technically challenging projects like the Pearl and Oryx Gas-to-Liquids (GTL) refineries that demanded attention.
The logic, then, was to prevent overexploitation of the precious North Field, particularly since it was shared with Iran, where it is known as South Pars. Detailed studies on the structure of the field have estimated that, at current production rates, Qatar still has about 135 years of gas reserves underground. With most of the giant Qatari projects now complete, the country can afford to exploit a little more. So 12 years later, the moratorium has been lifted.
Qatar Petroleum, the state oil firm, intends new development to be confined to the southernmost part of the North Field, running almost onshore, contributing a 10% increase – or 2 bcf/d or 400,000 barrels of oil equivalent in national production. It comes after QP merged its two gas subsidiaries – RasGas and Qatargas – into a single entity called Qatargas in December 2016, streamlining the business structure of its gas operations. Together with partners ExxonMobil, Total, Shell and ConocoPhillips, the new Qatargas will operate all Qatari LNG production, while the newly-established Ocean LNG will manage the international marketing of all Qatari LNG.
Put all of those announcements together and the picture is clear; Qatar is moving aggressively to retain its crown as the world’s top LNG exporter, fending off Australia, the USA and Russia as they ramp up their respective output. The flurry of LNG production has resulted in global installed LNG capacity of over 300 million tonnes a year, while only around 268 million tonnes of LNG were traded in 2016, Thomson Reuters data shows. That has helped pull down Asian spot LNG prices LNG-AS by more than 70 percent from their 2014 peaks to $5.65 per million British thermal units (mmBtu).
With LNG prices already waning due to the existing and coming glut, what good will it do for Qatar to add more to the mix?
Qatar's decision to lift the moratorium, is seen as a sign the country will not sit by idly as others scoop up customers in a growing market. For one thing, Qatari costs are low. Qatari LNG is already one of the cheapest to produce in the world, and any new North Field output can be tapped back into infrastructure already in place – allowing Qatar to better weather low LNG prices than say Australia, where Chevron has had to deal with massive ramp-ups in costs for the Gorgon and Wheatstone.
Secondly, the Qatar Petroleum announcement pointedly did not mention whether the new gas will become LNG. Which means Qatargas is looking at other options. More GTL and Gas-to-Petrochemical projects, perhaps? Or perhaps feeding the natural gas demand of its Gulf neighbours? The UAE, Bahrain, Oman, Kuwait and Saudi Arabia are short on natural gas, so a trans-Arabian Peninsula pipeline might be just what is needed. The lifting of the North Field moratorium also comes just in time since Qatar’s domestic oil and gas production is plateauing, kicking off the next phase of Qatari growth. And when that next phase begins to end, well, Qatar still has a whole lot more of the North Field to tap into. "What we are doing today is something completely new and we will in future of course ... share information on this with them (Iran)."
QP Chief Executive Saad al-Kaabi told reporters Monday at Qatar Petroleum's headquarters in Doha. "For oil there are people who see peak demand in 2030, others in 2042, but for gas, demand is always growing."
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Headline crude prices for the week beginning 11 February 2019 – Brent: US$61/b; WTI: US$52/b
Headlines of the week
Midstream & Downstream
Global liquid fuels
Electricity, coal, renewables, and emissions
2018 was a year that started with crude prices at US$62/b and ended at US$46/b. In between those two points, prices had gently risen up to peak of US$80/b as the oil world worried about the impact of new American sanctions on Iran in September before crashing down in the last two months on a rising tide of American production. What did that mean for the financial health of the industry over the last quarter and last year?
Nothing negative, it appears. With the last of the financial results from supermajors released, the world’s largest oil firms reported strong profits for Q418 and blockbuster profits for the full year 2018. Despite the blip in prices, the efforts of the supermajors – along with the rest of the industry – to keep costs in check after being burnt by the 2015 crash has paid off.
ExxonMobil, for example, may have missed analyst expectations for 4Q18 revenue at US$71.9 billion, but reported a better-than-expected net profit of US$6 billion. The latter was down 28% y-o-y, but the Q417 figure included a one-off benefit related to then-implemented US tax reform. Full year net profit was even better – up 5.7% to US$20.8 billion as upstream production rose to 4.01 mmboe/d – allowing ExxonMobil to come close to reclaiming its title of the world’s most profitable oil company.
But for now, that title is still held by Shell, which managed to eclipse ExxonMobil with full year net profits of US$21.4 billion. That’s the best annual results for the Anglo-Dutch firm since 2014; product of the deep and painful cost-cutting measures implemented after. Shell’s gamble in purchasing the BG Group for US$53 billion – which sparked a spat of asset sales to pare down debt – has paid off, with contributions from LNG trading named as a strong contributor to financial performance. Shell’s upstream output for 2018 came in at 3.78 mmb/d and the company is also looking to follow in the footsteps of ExxonMobil, Chevron and BP in the Permian, where it admits its footprint is currently ‘a bit small’.
Shell’s fellow British firm BP also reported its highest profits since 2014, doubling its net profits for the full year 2018 on a 65% jump in 4Q18 profits. It completes a long recovery for the firm, which has struggled since the Deepwater Horizon disaster in 2010, allowing it to focus on the future – specifically US shale through the recent US$10.5 billion purchase of BHP’s Permian assets. Chevron, too, is focusing on onshore shale, as surging Permian output drove full year net profit up by 60.8% and 4Q18 net profit up by 19.9%. Chevron is also increasingly focusing on vertical integration again – to capture the full value of surging Texas crude by expanding its refining facilities in Texas, just as ExxonMobil is doing in Beaumont. French major Total’s figures may have been less impressive in percentage terms – but that it is coming from a higher 2017 base, when it outperformed its bigger supermajor cousins.
So, despite the year ending with crude prices in the doldrums, 2018 seems to be proof of Big Oil’s ability to better weather price downturns after years of discipline. Some of the control is loosening – major upstream investments have either been sanctioned or planned since 2018 – but there is still enough restraint left over to keep the oil industry in the black when trends turn sour.
Supermajor Net Profits for 4Q18 and 2018
- 4Q18 – Net profit US$6 billion (-28%);
- 2018 – Net profit US$20.8 (+5.7%)
- 4Q18 – Net profit US$5.69 billion (+32.3%);
- 2018 – Net profit US$21.4 billion (+36%)
- 4Q18 – Net profit US$3.73 billion (+19.9%);
- 2018 – Net profit US$14.8 billion (+60.8%)
- 4Q18 – Net profit US$3.48 billion (+65%);
- 2018 - Net profit US$12.7 billion (+105%)
- 4Q18 – Net profit US$3.88 billion (+16%);
- 2018 - Net profit US$13.6 billion (+28%)