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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The UK has just designated the Persian Gulf as a level 3 risk for its ships – the highest level possible threat for British vessel traffic – as the confrontation between Iran with the US and its allies escalated. The strategically-important bit of water - and in particular the narrow Strait of Hormuz – is boiling over, and it seems as if full-blown military confrontation is inevitable.
The risk assessment comes as the British warship HMS Montrose had to escort the BP oil tanker British Heritage out of the Persian Gulf into the Indian Ocean from being blocked by Iranian vessels. The risk is particularly acute as Iran is spoiling for a fight after the Royal Marines seized the Iranian crude supertanker Grace-1 in Gibraltar on suspicions that it was violating sanctions by sending crude to war-torn Syria. Tensions over the Gibraltar seizure kept the British Heritage tanker in ‘safe’ Saudi Arabian waters for almost a week after making a U-turn from the Basrah oil terminal in Iraq on fears of Iranian reprisals, until the HMW Montrose came to its rescue. Iran’s Revolutionary Guard Corps have warned of further ‘reciprocation’ even as it denied the British Heritage incident ever occurred.
This is just the latest in a series of events around Iran that is rattling the oil world. Since the waivers on exports of Iranian crude by the USA expired in early May, there were four sabotage attacks on oil tankers in the region and two additional attacks in June, all near the major bunkering hub of Fujairah. Increased US military presence resulted in Iran downing an American drone, which almost led to a full-blown conflict were it not for a last-minute U-turn by President Donald Trump. Reports suggest that Iran’s Revolutionary Guard Corps have moved military equipment to its southern coast surrounding the narrow Strait of Hormuz, which is 39km at its narrowest. Up to a third of all seaborne petroleum trade passes through this chokepoint and while Iran would most likely overrun by US-led forces eventually if war breaks out, it could cause a major amount of damage in a little amount of time.
The risk has already driven up oil prices. While a risk premium has already been applied to current oil prices, some analysts are suggesting that further major spikes in crude oil prices could be incoming if Iran manages to close the Strait of Hormuz for an extended period of time. While international crude oil stocks will buffer any short-term impediment, if the Strait is closed for more than two weeks, crude oil prices could jump above US$100/b. If the Strait is closed for an extended period of time – and if the world has run down on its spare crude capacity – then prices could jump as high as US$325/b, according to a study conducted by the King Abdullah Petroleum Studies and Research Centre in Riyadh. This hasn’t happened yet, but the impact is already being felt beyond crude prices: insurance premiums for ships sailing to and fro the Persian Gulf rose tenfold in June, while the insurance-advice group Joint War Committee has designated the waters as a ‘Listed Area’, the highest risk classification on the scale. VLCC rates for trips in the Persian Gulf have also slipped, with traders cagey about sending ships into the potential conflict zone.
This will continue, as there is no end-game in sight for the Iranian issue. With the USA vague on what its eventual goals are and Iran in an aggressive mood at perceived injustice, the situation could explode in war or stay on steady heat for a longer while. Either way, this will have a major impact on the global crude markets. The boiling point has not been reached yet, but the waters of the Strait of Hormuz are certainly simmering.
The Strait of Hormuz:
Headline crude prices for the week beginning 8 July 2019 – Brent: US$64/b; WTI: US$57/b
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Utility-scale battery storage units (units of one megawatt (MW) or greater power capacity) are a newer electric power resource, and their use has been growing in recent years. Operating utility-scale battery storage power capacity has more than quadrupled from the end of 2014 (214 MW) through March 2019 (899 MW). Assuming currently planned additions are completed and no current operating capacity is retired, utility-scale battery storage power capacity could exceed 2,500 MW by 2023.
EIA's Annual Electric Generator Report (Form EIA-860) collects data on the status of existing utility-scale battery storage units in the United States, along with proposed utility-scale battery storage projects scheduled for initial commercial operation within the next five years. The monthly version of this survey, the Preliminary Monthly Electric Generator Inventory (Form EIA-860M), collects the updated status of any projects scheduled to come online within the next 12 months.
Growth in utility-scale battery installations is the result of supportive state-level energy storage policies and the Federal Energy Regulatory Commission’s Order 841 that directs power system operators to allow utility-scale battery systems to engage in their wholesale energy, capacity, and ancillary services markets. In addition, pairing utility-scale battery storage with intermittent renewable resources, such as wind and solar, has become increasingly competitive compared with traditional generation options.
The two largest operating utility-scale battery storage sites in the United States as of March 2019 provide 40 MW of power capacity each: the Golden Valley Electric Association’s battery energy storage system in Alaska and the Vista Energy storage system in California. In the United States, 16 operating battery storage sites have an installed power capacity of 20 MW or greater. Of the 899 MW of installed operating battery storage reported by states as of March 2019, California, Illinois, and Texas account for a little less than half of that storage capacity.
In the first quarter of 2019, 60 MW of utility-scale battery storage power capacity came online, and an additional 108 MW of installed capacity will likely become operational by the end of the year. Of these planned 2019 installations, the largest is the Top Gun Energy Storage facility in California with 30 MW of installed capacity.
As of March 2019, the total utility-scale battery storage power capacity planned to come online through 2023 is 1,623 MW. If these planned facilities come online as scheduled, total U.S. utility-scale battery storage power capacity would nearly triple by the end of 2023. Additional capacity beyond what has already been reported may also be added as future operational dates approach.
Of all planned battery storage projects reported on Form EIA-860M, the largest two sites account for 725 MW and are planned to start commercial operation in 2021. The largest of these planned sites is the Manatee Solar Energy Center in Parrish, Florida. With a capacity of 409 MW, this project will be the largest solar-powered battery system in the world and will store energy from a nearby Florida Power and Light solar plant in Manatee County.
The second-largest planned utility-scale battery storage facility is the Helix Ravenswood facility located in Queens, New York. The site is planned to be developed in three stages and will have a total capacity of 316 MW.