LNG Prices

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OPINION Jun 25 2015 at 3:45 PM Updated Jun 25 2015 at 5:56 PM
Asian LNG sales contracts under pressure as prices diverge

The sun might be setting on old-style, cast-iron LNG sales contracts. Glenn Hunt

by Angela Macdonald-Smith
That people can even speculate that a long-term LNG sales contract might be broken says something about the tension prevailing in the Asian market.

The multi-decade contracts that form the backbone of Asian LNG trade have always had an almost sacred quality, relied upon as cast-iron by developers of multibillion-dollar supply projects and their lenders. Reputations, as buyers and sellers, are too precious to compromise.

But something is afoot. While there's no evidence that any contract will be reneged upon, talk has emerged in recent weeks of efforts afoot to have terms modified in ways that would have been unthinkable in the past.

At the root of the problem is the wide gap that has opened between spot and contract prices for LNG in Asia, which combines with other factors to suggest we are entering new territory. Spot prices that were trading up to a third higher than contract prices in early 2014 are well below now and are expected by many to remain so for the rest of the decade.


The increased depth in the market has contributed, with more buyers, more sellers and more traders, each with their own drivers and some under intense economic pressure.

Energy forecaster Fereidun Fesharaki, who has close links with many large Asian buyers, says that while producer-buyer relationships are still important, pressure is mounting on all sides to renegotiate contracts.

In the spotlight this week has been Origin Energy's $24.7 billion Australia Pacific LNG venture nearing completion in Queensland, and whether big customer Sinopec is seeking to modify contract terms to perhaps slow down its commercial purchases or to re-sell LNG elsewhere.

FALLING DEMAND

China's LNG demand has been falling dramatically short of some forecasts, as economic growth slows and high domestic prices discourage demand. Wood Mackenzie estimates China has contracted 18 billion cubic metres more than its LNG needs in 2015-17.

China has form in wreaking change in commodity markets: its favouring of cheaper iron ore from the spot market over contract supplies led to the end of the dominance of annual contracts in that sector.

But Origin boss Grant King dismissed this week any concerns over Sinopec's commitments to take its full 7.6 million tonnes a year volume from APLNG, saying he had "no reason to think" the Chinese customer wouldn't stick with the terms, which require it to pay for the gas even if it doesn't take delivery.

King emphasised the flexibility that is typically built into LNG purchase contracts early on to allow for the particular circumstances that a new buyer or seller might find itself in. That would include flexibility to re-sell gas outside of the home market, which he said was "perfectly normal", apparently even if that would depress prices further in an Asian spot market that APLNG itself might need to call on.

But it's not just Sinopec. Fesharaki also points to efforts by India's Petronet to renegotiate a big LNG contract and reportedly take less than its contracted purchase volume. PetroChina too.

On the buyer's side, the North West Shelf venture is known to be keen to re-negotiate the rock-bottom 25-year sale contract it signed with China's CNOOC in 2002 if any opening could be found. In the meantime, it is said to be using any means possible to limit deliveries under the deal.

Fesharaki believes the scene is getting set for change, particularly as surging LNG supplies from Australia and the US keep spot prices about $US3 ($3.88) per million British thermal units below contracts in low season, providing plenty of motivation for buyers.

"A key question is whether a Japanese, Korean, or Taiwanese buyer might more openly pursue a strategy of buying low‐priced spot cargoes while backing out of long‐term contracted volumes," he told clients this month.

"This may seem unlikely, but given the challenges many Japanese utilities face, it is not implausible."

Fesharaki suggests that could lead buyers and sellers to start seeking a pricing linkage that more accurately reflects short-term market conditions. Change is afoot indeed.

amacdonald-smith@fairfaxmedia.com.au

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LNG firm Cheniere Energy plans expansion in the US
GEOFF HISCOCK THE AUSTRALIAN JULY 20, 2015 12:00AM

LNG firm plans US expansion

One of Australia’s biggest potential rivals in the global LNG trade, Houston-based Cheniere Energy, has given the green light for up to seven more gas processing trains on the US Gulf Coast that could lift its annual export capacity to 60 million tonnes by 2025.

Cheniere has already committed to five trains at its Sabine Pass liquefaction project in Louisiana and three at Corpus Christi in Texas. The proposed new trains would expand Corpus Christi and would add two new mid-size projects in Louisiana.

Cheniere is less than six months away from producing its first LNG for export from the 4.5mtpa Train 1 at Sabine Pass, which will mark the first US export of LNG outside Alaska. That gas will go to BG Group under a 20-year long-term supply agreement.

During 2016-17, Cheniere will add another 13.5mtpa of capacity as trains two, three and four come on stream at Sabine Pass. Two more trains are planned for the site, with train five now expected to begin operating in 2018 after the Cheniere board approved a favourable final investment decision for it on June 30, while train six is waiting in the wings.

According to Cheniere chairman and chief executive Charif Souki, all regulatory approvals are in place for train 6, and a final investment decision will be made once commercial contracts and financing are arranged.

Gas Natural Fenosa of Spain, Korea Gas, GAIL India, Total Gas & Power and British energy utility Centrica will take most of the output from trains two to five, with about 2mtpa left over for spot sales.

In a presentation this month, Cheniere says its break-even price range for its Gulf Coast LNG delivered ex-ship to Asia is between $US7.70 ($10.44) and $US8.40 per million metric British thermal units (MMBtu). In comparison, it estimates the break-even price for LNG from West Africa is $US9.50 to $US11.50, and $US14 to $US16 for northwest Australia.

The July spot price for LNG delivered to Asia is $US7.60, according to data from commodity information company Platts.

In its July 10 report, Oil & Gas Reality Check 2015, the Deloitte Centre for Energy Solutions said LNG was now very much a buyer’s market. It said high project development costs would, for example, “hamper Australian attempts to cost-effectively supply global consumers”.

It said this was “especially true in the current low-price environment”.

Qatar is the world’s cheapest gas producer and is currently the world’s biggest LNG seaborne exporter, with 77 million tonnes of annual capacity, ahead of Australia, Malaysia and Indonesia. Australia is expected to overtake Qatar by 2018 as new projects and expansions begin producing on the North West Shelf, the Northern Territory and in Queensland, where three coal seam gas-based LNG plants have been built on Gladstone’s Curtis Island.

BG Group’s Queensland Curtis LNG has already begun exports from its two trains, and the Santos Gladstone LNG and Origin-ConocoPhillips Australia Pacific LNG projects are expected to begin exports over the next few months.

If the three Gladstone LNG plants, the Darwin-based Ichthys development in 2017, and the Gorgon (late 2015), Wheatstone (2016) and Prelude (2017) projects on the North West Shelf all come to fruition on schedule, Australia will have about 85mtpa of export capacity in 2018.

All suppliers are targeting the Asian LNG market, where demand is expected to reach 270 million tonnes a year in 2020 and 314 million tonnes in 2025, according to the latest estimates from energy analyst Wood Mackenzie. The biggest customer for seaborne LNG is Japan, with annual imports of about 80 million tonnes, followed by South Korea and China. India is also growing in importance as a customer.

But price is an issue, with recent lower demand in China putting pressure on suppliers that include not just Qatar and Australia, but Papua New Guinea — where the ExxonMobil-Oil Search venture began shipments last year from its 6.6mtpa Port Moresby facility — and Russia, Africa and Southeast Asia.

Complicating the picture is the imminent arrival of new supply from North America, where a combination of pipeline networks, finance, skilled labour and technological advances mean companies like Cheniere, Louisiana-based rival Cameron LNG from 2017 and Texas-based Freeport LNG from 2018, can liquefy abundant and cheap shale gas and ship it to Asia competitively.

Cheniere, a relatively small producer with a market cap of about $US16 billion, claims in its presentation that it “can profitably sell LNG into key demand centres even in periods of lower market prices” and that “if LNG prices remain at lower levels, we would expect LNG demand to increase, thus signalling the need for more liquefaction projects.” In addition to its six-train 27mtpa Sabine Pass project, Cheniere has started work on the first two trains of its similar Corpus Christi project, where it hopes to begin exports in 2018. Its customers there are Pertamina of Indonesia, European utilities Endesa, Iberdrola, Gas Natural Fenosa, EDF and EDP, and Singapore-based Woodside Energy Trading.

In a statement last month announcing an expansion of Corpus Christi, Mr Souki said the site eventually would have 22.5mtpa of capacity from five trains. He said work on the final three trains could begin in 2017, with production in 2021.

In addition to Sabine Pass and Corpus Christi, Cheniere last month struck an in-principle partnership with Houston-based Parallax Enterprises covering four new trains of 2.5mtpa each, for a total of 10mtpa over two sites on the Gulf Coast. One is known as Live Oak LNG in southwestern Louisiana and the other is Louisiana LNG, on the Mississippi River 60km from New Orleans.

Mr Souki said the two extra trains at Corpus Christi and the proposed four-train partnership with Parallax would “bring our expected aggregate nominal LNG production capacity to about 60 mtpa by 2025”.

Mr Souki said Cheniere expected that the new liquefaction trains could be funded from internal cash flows.

Geoff Hiscock writes on international business and is the author of “Earth Wars: The Battle for Global Resources”, published by Wiley

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Aug 6 2015 at 3:57 PM Updated Aug 6 2015 at 7:44 PM

Qatar's dirt-cheap LNG is making it the new energy superpower


The Al Rekayyat, a liquefied natural gas tanker, docked in Ras Laffan, Qatar, May 23, 2015. Operated by Royal Dutch Shell but owned by the emirate, the Rekayyat can carry around $30 to $40 million worth of liquefied natural gas. ANDREW TESTA
by Stanley Reed

The temperature hovered around 38 degrees on the jetty here, where a set of pipes were connected to a giant red-hulled ship. But the moisture in the air froze on the pipes and flaked off, creating snowlike flurries on the early summer evening.

The incongruous sight is common on the Qatari ship, the Al Rekayyat, which carries a frigid fuel known as liquefied natural gas.

Natural gas, when chilled to minus 162 degrees, turns into a liquid with a fraction of its former volume. The process has reshaped the natural gas business, allowing the fuel to be pumped onto ships and dispatched around the world.

After investing tens of billions of dollars, Qatar is at the forefront. Part of the emirate's fleet, the Al Rekayyat, run by Royal Dutch Shell, goes to Fujian in China and Yokkaichi in Japan, as well as Dubai and Milford Haven in Wales.

Natural gas cools into liquid form in one of the 14 'trains' which can stretch up to three-fifths of a mile, at Ras Laffan, Qatar.
Natural gas cools into liquid form in one of the 14 'trains' which can stretch up to three-fifths of a mile, at Ras Laffan, Qatar. ANDREW TESTA
When loading was finished recently, four tugboats pulled the ship from its berth with a deep roar. "I expect to be in the north channel around midnight," said the captain, Veerasekhar Rao Muttineni, over the marine radio, as the ship eased into the waters of the Persian Gulf. Four days later, it docked in Hazira on the west coast of India.

Once a poor nation whose economy depended on fishing and pearl diving, Qatar is a relatively new giant in the global energy trade.

In the 1970s, Shell discovered the world's largest trove of natural gas, called the North field, in Qatari waters. But there was no market for the fuel. Potential customers in Europe were too far to reach via pipeline, the usual method. Shell walked away.

Looking to the example of Malaysia and Indonesia, Qatar and Hamad bin Khalifa al-Thani, who was then its emir, started promoting LNG in the mid-1990s. Exxon Mobil was the important early investor; Shell, Total and ConocoPhillips soon followed.

Natural gas flares burn at the port of Ras Laffan, Qatar. Though Qatar is a relatively new giant in the global energy trade, an investment of tens of billions has put the emirate at the forefront of the processing, storage and shipment of liquefied natural gas.
Natural gas flares burn at the port of Ras Laffan, Qatar. Though Qatar is a relatively new giant in the global energy trade, an investment of tens of billions has put the emirate at the forefront of the processing, storage and shipment of liquefied natural gas. ANDREW TESTA
A THIRD OF THE WORLD'S LNG

Qatar and its energy partners took the business to a new level, developing far bigger and more efficient plants. Last year, Qatar produced about a third of all liquefied natural gas, although Australia and the United States have big export ambitions.

It is a lucrative business that has made Qatar the world's wealthiest country by output per capita. While industry growth has recently been flat, worldwide volumes have roughly quadrupled in the last two decades to about 240 million metric tons a year, accounting for about one-third of overall gas exports. Annual sales are worth an estimated $US180 billion.

"With the full development of Qatar, LNG came of age," said Michael Stoppard, chief gas strategist at IHS, a market research firm. "Qatar made LNG a bigger business – bigger projects, bigger ships, bigger volumes and a much bigger global footprint."

Workers at the huge liquefied natural gas terminal in Ras Laffan, Qatar.
Workers at the huge liquefied natural gas terminal in Ras Laffan, Qatar. ANDREW TESTA
Ras Laffan, a desert headland about an hour's drive from Qatar's capital, Doha, bristles with storage tanks, pipelines and other gas processing facilities. Gas comes in from offshore wells and then passes through a series of refrigeration units that clean the fuel and chill it to liquid form. Qatar Gas and RasGas, the emirate's two exporting companies, have 14 of these facilities, known as trains.

"We pushed the R&D to go another step, to increase the size," said Ibrahim Bawazir, a Qatar Gas executive, as he led a group of visitors dressed in orange fire-resistant suits around Qatargas 4, one of the largest and most modern installations. It stretches for three-fifths of a mile. "It is almost impossible to build LNG on this scale," Bawazir said.

FRACTION OF THE COST OF US, AUSTRALIA

With the ability to produce and process such huge quantities of gas, Qatar can keep its costs low. IHS estimates that it costs about $US2 per million British thermal units, a standard natural gas measure, to produce and liquefy gas in Qatar. That compares with $US8 to $US12 for planned projects in the United States, East Africa and Australia. The low cost structure allows Qatar to be more nimble and make money even in the current weak environment, when prices are low.

The Qataris originally planned to deliver much of their LNG to the United States and Europe, but those plans were frustrated by the shale gas boom in North America. Instead, three-quarters of Qatari gas flowed last year to Asian countries like China, India and South Korea. Japan was Qatar's largest customer as the country's electric utilities substituted natural gas generation for nuclear after the 2011 Fukushima disaster.

Qatar's shift toward Asia mirrors broader trading patterns in the oil industry. In recent years, gulf producers like Saudi Arabia, Iraq and Iran have increasingly focused on Asia, where demand for energy imports is growing. Qatar is well placed to serve Asian markets, particularly India, which is only a few days' sail across the Arabian Sea.

A vital part of Qatar's effort has been a new fleet of carriers, which are substantially larger and more efficient than previous models.

At over 300 metres, the Al Rekayyat, which was built in South Korea in 2009, is only slightly shorter than the largest aircraft carrier. The ship carries up to 217,000 cubic meters of gas, about 7.7 million cubic feet, worth around $US30 million to $US40 million at today's market prices.

TOO FAST FOR PIRATES - HOPEFULLY

The Al Rekayyat is surprisingly fast for such a large ship. It cruises at about 18 knots, a speed that the crew figures makes it too fast to be easily boarded by pirates.

Still, the crewmen are cautious. On the first morning of the voyage, crewmen wearing heavy leather gloves, padding and hard hats rigged up barbed wire and water cannons to ward off pirates. "This is recommended good practice," Rao said. "We look on with suspicious eyes."

Later that day, the ship entered the narrow choke point at the east end of the gulf, the Strait of Hormuz. Rao was on the bridge with a navigator, Ervin Markovic, and two crewmen scanning for trouble with binoculars. Shrouded in the heat haze above the pale green water, Iran lay ahead and to the port side of the ship. To starboard loomed a rocky outcropping from the coast of Oman.

The strait, through which about one-third of the world's waterborne oil exports travel, is one of those passages that mariners approach with a sense of trepidation. The high volumes of maritime traffic combined with narrow shipping lanes increase the risk of collisions. Just a few weeks before this trip, a cargo ship had been detained by an Iranian gunboat.

"You don't know what to expect," Markovic said.

The cargo carries its own risks.

The greatest danger, experts say, is that the liquid might escape and expand into a flammable, asphyxiating cloud. On a ship like the Al Rekayyat, the LNG is contained in special tanks designed to minimize the likelihood of leaks.

OBSESSIVELY CAUTIOUS

LNG requires a near obsession with precautions, drills and safety. Shell's rules prohibit taking devices like mobile phones or cameras that could spark an explosion on deck. Alcohol is not permitted. Crew members rarely go outside unless for work.

Miroslav Ahmetovic, the chief officer, spends much of his workday in a room below the bridge monitoring the LNG cargo on screens that display indicators like pressure and volume. Every few hours he dons hard hat, gloves, goggles and protective clothing and goes out on the sweltering deck to see that nothing is amiss.

"I want to make sure my video game conforms to reality," Ahmetovic said, emphasising the constant vigilance that Shell requires.

More than a day's journey away from India, the ship's crew was already preparing for port. Ahmetovic gradually began easing open the valves to the LNG tanks, letting the cold fluid gradually chill the pipes so they would not crack from sudden cold.

"If you don't treat the cargo right, it will break the ship," he said.

Rao stood on the bridge with a crewman at the wheel testing the engine and the steering. He even tried a full reversal of the engines, which might be required in an emergency. Gathering his officers around him, he warned them to pay close attention unloading the fuel so there were no mistakes.

"If you are idle, ask yourself what you are missing," he instructed.

INDIA CAN'T GET ENOUGH

On the fourth day, the Al Rekayyat eased through the narrow harbor entrance, coming to a halt at a modern jetty. From there pipes took the fuel to two large storage tanks, which fed the liquid into a long series of cylinders and other vessels. The fuel is gradually rewarmed back into a gas, so that it can be piped into the Indian pipeline network outside.

The terminal area is almost spotlessly clean, with staff members dressed in neat blue uniforms. Outside the gates is a different matter. Trucks grind along muddy roads lined with ramshackle shelters. Families drawn by the prospects of work in the factories camp under bridges.

Nilay Vyas, the general manager of Hazira, says that the pipelines buried in the ground outside the terminal are monitored by an optical fibre system that would "give a signal in case of unauthorised work." A patrol also goes out at least four times a day, he says, to check in person.

Shell, which has made a bigger bet on gas than any of its rivals, opened the Hazira terminal in 2005 with the French giant Total as a junior partner. The terminal, the company figured, would supply the power plants and factories in the fast-growing industrial areas nearby.

In the early days, Shell struggled to find customers, until the state's gas distribution system was expanded and Hazira connected. Now, the Indian economy is growing at a decent clip and the country faces an energy shortage. Customers, says Shell, are lining up, viewing LNG as a clean, reliable source of energy.

Maarten Wetselaar, the head of Shell's global gas business, said Hazira's gas receiving and processing facilities were "completely sold out."

"Even if you begged us on your knees for a slot," he said, "I don't think in the next 12 months we could accept another cargo."

The New York Times

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·        Aug 20 2015 at 4:42 PM 
 
·         Updated Aug 20 2015 at 8:25 PM 
'Sweet spot' turns to 'storm' for new LNG producers
Gorgon LNG was intended to hit the market 'sweet spot' but has run behind schedule. 

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by Angela Macdonald-Smith
It wasn't supposed to be like this. Chevron's huge Gorgon liquefied natural gas project was intended to begin production to hit a "sweet spot" in the market. The other new LNG projects springing up around the country would supply much-needed gas to importers seeking to satisfy robustly growing demand at prices to match.
As it is, the $180 billion of new LNG ventures around the country are facing one of the bleakest markets Asia has seen for export gas for years.
Demand has not met the growth forecasts of the past few years, while LNG prices have followed oil south. On the supply side, the delay in the start-up of the troubled $US54 billion Gorgon project from its original schedule of late 2014 into what now is likely to be only 2016, has inflated the volume of gas set to hit markets over the next 12 months. 
Most of the LNG is locked away under long-term contracts and so relatively protected from the glut, save the link to oil prices. But the spot market is still expected to be awash with surplus LNG from the "commissioning cargoes" shipped during the ramp-up phase of new projects, and as buyers that have signed up for more LNG than they can now sell, looking to on-sell cargoes to others.

Some ventures have been planning to have some LNG available for spot sales, remembering that not long ago, the prices available for short-term sales made that look a good idea. 
Spot LNG prices are down to about $US8 a gigajoule, down from about $US20 in early 2014.
SPOT MARKET STILL WEAK
Woodside Petroleum chief executive Peter Coleman is expecting another 18 months of weak prices in the spot LNG market as buyers try to absorb the new supplies from Australia and as demand disappoints in key markets such as China.
Coleman says Woodside locked in mid-term LNG sales contracts, such as the early 2014 deal with Japan's Chubu Electric, in anticipation of the weakness and to cut exposure to the spot market. 
He says the sector was "in the middle of a storm", which would not last forever. "It will pass and those who have prepared themselves for it, will weather it particularly well. Those who haven't, I can't predict what that will look like." 
Origin Energy, with its $25 billion Australia Pacific LNG project just months away from shipping its first cargo, is arguably deeper in the "storm" than Woodside, posing some challenges for chief executive Grant King.
Forecasts several years ago that Origin would reap $1 billion a year of cash flows from APLNG were based on a $100 a barrel oil price. At today's prices – closer to $64 in Australian dollars – it looks quite different, at less than $200 million.
But King declares there's still good money to be made from APLNG, even after the tumbling oil price has slashed LNG prices to about $US8 a gigajoule. That translates to about $10-$11, which translates to a "netback" price – excluding the costs of shipping LNG – of $9-$10, triple the historical price for gas sold in Australia's east coast.
"It still produces a value for gas resources in Australia higher than would otherwise have been the case in the domestic market," King says.
So while prices are too low to drive investment in new LNG projects, the incentive is there to maximise output from existing plants once they start up, King says. He anticipates LNG plant owners will take a leaf out of the iron ore majors' book and run them flat out, potentially above their rated capacity, as they go head-to-head wth US export ventures for short-term demand.
amacdonald-smith@afr.com.au

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NT sits on gas bonanza worth billions, says report
Date: August 25 2015

Angela Macdonald-Smith


The Northern Territory is sitting on a treasure trove of unconventional gas that could deliver thousands of jobs and almost $1 billion of government revenue if costs can be reduced to make development economic, a new report has found.
The analysis by Deloitte Access Economics, to be released on Wednesday, puts the potential increase in the NT's gross state product at a cumulative $22.4 billion over the 2020-40 period in the "aspirational" scenario that sees shale and tight gas developed both for LNG and for supply to east-coast markets.
Even in the "success" scenario, which envisages a slightly more modest development, the increase to the NT's gross state product is put at $17.2 billion over the 20 years compared with a scenario where the gas stays in the ground.
The NT could hold a massive 234 trillion cubic feet of shale gas, says the territory's Geological Survey, an estimate that has lured several international players working to test acreage by drilling. Last week, junior explorer Armour Energy revealed an initial deal with American Energy Partners, the company of United States shale pioneer Aubrey McClendon, for a $US100 million ($139 million)  exploration venture that would see AEP take a 75 per cent stake in acreage in the NT's McArthur Basin.
"While still in its very early stages, shale gas could underpin a new wave of investment delivering jobs and economic opportunities for decades to come," said Malcolm Roberts, the new chief executive of the Australian Petroleum Production & Exploration Association, which commissioned the Deloitte report.
Mr Roberts said shale could be "a game-changer" for future NT governments by delivering a new source of revenue to better fund services and infrastructure development.  But he said a "stable, secure and competitive" regulatory framework was needed to encourage investment.
Gas under pressure
The collapse in oil prices has put all oil and gas developments in Australia and elsewhere under pressure, and looks set to push out the prospects for the local shale industry. Earlier this year, US energy giant Chevron walked away from a major unconventional exploration program with Beach Energy in the Cooper Basin in central Australia, a region that is seen as offering some advantages over the NT because of its existing petroleum plants and pipelines.
Deloitte said in the report that while shale and tight gas resources are generally more costly to extract than conventional gas, the vast scale of the resource still pointed to the potential for rapid development.
The release of the report follows findings released by an NT inquiry into hydraulic fracturing in March that the environmental risks involved with the controversial process could be managed effectively. But the industry is still facing opposition from environmental groups and some indigenous groups concerned about potential harm to water and land resources.
Deloitte estimates 6321 long-term jobs could be created in its "aspirational" scenario for unconventional gas, which assumes the development of three LNG expansion trains in the NT to export shale and tight gas, and up to 84 petajoules a year of production for east-coast markets, that would be supplied through a proposed new pipeline between the NT and east-coast gas grids. Supply to the NT market would rise to as high as 79 PJ a year.
The "success" scenario, which would create almost 4200 jobs, assumes two brownfield LNG trains, up to 56 PJ a year of gas to the east coast and up to 30 PJ into the NT market.

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ConocoPhillips mulls major offshore gas project to keep Darwin LNG going
DateAugust 26, 2015 - 12:00AM

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[Image: 1429997340926.png]
Angela Macdonald-Smith
Energy Reporter

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Conoco is mulling an offshore gas project to keep its Darwin LNG plant running.

US oil major ConocoPhillips is targeting mid-2018 for a go-ahead on a potential $US15 billion ($21 billion) offshore gas development off northern Australia to feed its Darwin liquefied natural gas project once current supplies have run out, but says an expansion of the venture isn't viable without a sharp drop in costs.
Frank Krieger, vice-president of exploration and development for Conoco in Australia, said that either the Caldita-Barossa gas fields in the Timor Sea or the Poseidon fields in the Browse Basin could be developed, but only as "backfill" for Darwin LNG, not an expansion.

In terms of our global portfolio the price to build a brownfield LNG train in Darwin just really isn't competitive at the moment. 

That gas would be used to keep the LNG project in operation after the existing offshore gas source, the Bayu-Undan field in the Timor Sea, is depleted in 2022 or 2023.
Darwin LNG, which produces about 3.7 million tonnes a year of LNG, has long been regarded as prime for expansion given it already has development approval to take capacity at the site to 10 million tonnes. But Mr Krieger signalled an expansion is highly unlikely after the significant inflation in costs since the original plant was built, particularly given weak oil prices.
Darwin LNG cost about $US3 billion, compared with $US15 billion for Woodside Petroleum's similar-sized Pluto venture several years later, while projects currently under construction are much more expensive.
"Darwin LNG was built in a low-price environment and it's clearly the most economic way for us to monetise our gas resources," Mr Krieger said in an exclusive interview ahead of a conference address in Darwin on Wednesday.
"In terms of our global portfolio the price to build a brownfield LNG train in Darwin just really isn't competitive at the moment, so we'll need to see significant cost deflation to drive us to want to do that or to have it compete in our portfolio."
Significant development
The development of Caldita-Barossa or of Poseidon would still be significant, requiring between $US7 billion and $US15 billion for the offshore facilities and a pipeline to take gas to a point on the existing Bayu-Undan pipeline where it can be shipped to Darwin, Mr Krieger suggested.
The project would involve offshore development of the fields using a production ship or offshore rig, and a 250-kilometre pipeline in the case of Caldita-Barossa, or a 640-kilometre pipeline for Poseidon.
Work on both options is running in parallel, with a decision on the preferred development expected in mid-2017 when front-end engineering and design (FEED) work would start.
"We're in appraisal at the moment so we're going to assess which one of those is the best candidate and we'll bring that forward with the LNG partners and the joint ventures which we represent," Mr Krieger said. "We see them as fairly equal at the moment."
Conoco is partnered by Chinese oil giant PetroChina and Origin Energy in Poseidon, while its partners in Caldita-Barossa are South Korea's SK E&S and Santos. Poseidon holds more gas and is more liquids rich than Caldita-Barossa, but is farther away and lies in deeper water.
Mr Krieger said that the presence of PetroChina and SK presented options for selling LNG from the Darwin project, while the venture's existing customers, Tokyo Gas and Tokyo Electric, could also want to extend supplies.
The Bayu-Undan Production Sharing Contact expires in in 2022.
Mr Krieger said that while Conoco is starting to see some cost deflation in Australia, "more work is needed to remain globally competitive." But he says the economics of leveraging existing assets such as the Darwin plant "cannot be ignored".
Both Santos and Origin have had their balance sheets stretched y their respective Queensland LNG projects, but Mr Krieger said that despite the weak oil price environment, there was no pressure from partners to slow down work on either Poseidon or Caldita-Barossa. 

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LNG downturn risks muted: HSBC

• BUSINESS SPECTATOR
  
• SEPTEMBER 14, 2015 12:10PM
  

Michael Roddan
[Image: michael_roddan.png]
Reporter

[b]Australia is likely to be partly insulated from any downturn in the country’s imminent liquefied gas boom, thanks to the largely foreign-owned nature of the $220 billion LNG export projects, says HSBC.[/b]
The nation’s gas export boom is forecast to boost local economic growth over the next three years, but the exposure the country faces to upswings or downturns in the industry will be muted, says HSBC Australia and New Zealand chief economist Paul Bloxham.
More than $220 billion was invested in LNG plants during the resources boom, with the projects expected to grow export capacity to 85 million tonnes a year from 20 million tonnes currently.
Australia will overtake Qatar to be the world’s largest liquefied gas exporter by 2018, and the production ramp up is expected to add 0.6 percentage points to GDP growth each fiscal year from 2016 to 2018.
The LNG boom will assist the pick-up in the tourism and education sectors that has already been boosted by the tumbling Australian dollar.
“It is hard to get the overall economy to look too weak with that sort of positive contribution,” Mr Bloxham said.
The new LNG projects are almost entirely owned and run by multinationals, which Mr Bloxham said would shield Australia from the full upside and downside risks involved with the industry.
“There is a clear risk-sharing relationship with the rest of the world at work,” he said.
“Although Australia’s economy may therefore not have benefited from all of the upside from these projects, it should also only be expected to suffer from part of any downside.”
Much of the export volume had been forward sold to Japan, China and South Korea and benchmarked to the oil price, and softer economic growth forecasts for East Asia might push down LNG prices, rather than volumes, Mr Bloxham said.
Last week, the International Energy Agency said six liquefied natural gas projects under construction in Australia would struggle to break even due to the weak oil price.
The IEA also raised doubts any new LNG projects would be given the go-ahead for expansion this decade.
The sharp fall in oil prices since mid-2014 was likely to limit the short-term profitability of many of the projects, which would drag on corporate and state tax receipts, Mr Bloxham said.
But the LNG projects have been built with 30- to 50-year production timelines in mind, so weaker short-term profitability — or even losses — shouldn’t stop the ramp up in export volumes which will support GDP growth regardless, according HSBC.
“While some observers are, once again, starting to get worried that Australia could see a recession at the end of the mining boom, we remain more positive,” Mr Bloxham said.
“As we noted last week, much of this positive view is due to the current upswing in the housing and services sectors, supported by low interest rates and recent falls in the Australian dollar.”

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• Oct 1 2015 at 5:12 PM 
   
  
  
•  Updated Oct 1 2015 at 8:15 PM 
  

LNG market weakness to put Maurice Brand's LNG Ltd to the test

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[img=620x0]http://www.afr.com/content/dam/images/1/2/i/1/f/2/image.related.afrArticleLead.620x350.gjxla3.png/1443694506295.jpg[/img]The Maurice Brand-led LNG Ltd is already suffering a crisis of confidence in a market where it had until recently been a firm favourite. Dominic Lorrimer
[Image: 1429997340926.png]

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by Angela Macdonald-Smith
A shiver ran up the collective spine of the liquefied natural gas supply sector this week as reports emerged that India's Petronet was set to break its long-term contract to buy LNG from Qatar.
Prices were so low in the spot market, the report went, that India's biggest importer of LNG was willing to risk incurring penalties on its 25-year contract with Qatar's RasGas  rather than keep on buying its full allotment of gas at higher prices.
Only a few weeks earlier, news that China's state-controlled oil giant CNOOC would seek to re-sell two LNG cargoes from BG Group's Queensland Curtis plant had rattled the market.
It all reflects a market awash with cheap LNG, even before most of the Queensland exports start up. Platts prices for spot LNG in north-east Asia for October average just $US7.54 per million British thermal units, down from around $US20 early last year.

It is in this environment that aspiring US LNG exporter Liquefied Natural Gas Ltd is aiming to lock customers into long-term contracts to use its proposed Magnolia export terminal in Louisiana.
As Asian LNG prices have dived, some are questioning the whole viability of US LNG exports.
Zin Smati, head of the North American business of Engie, formerly GDF Suez, was quoted last week as saying "nobody" could make money from US LNG exports at present: the price advantage that US exports had over Asian prices has vanished as oil prices dive.
The Maurice Brand-led LNG Ltd is already suffering a crisis of confidence in a market where it had until recently been a firm favourite. After being the S&P/ASX200's fourth-best performer in the June half, it is now among the worst for the year-to-date, the stock sliding from $5 in late April to a low of $1.23 this week.


DELAYS ADD TO THE TURMOIL
Delays in LNG Ltd signing up customers and finalising an engineering contract has added to the turmoil that has gripped the whole of the resources sector.
Now, in this fourth quarter, the assurances Brand has given to shareholders will be put to the test. He has given early this quarter as the revised date for finalising the engineering contract for the Magnolia plant with KBR and South Korean firm SKE&C, while at least one of the preliminary agreements with customers is to be firmed into a contract by December.
Brand admits that the concept of US gas exports is a harder sell at present. But he says the various motivations of his potential customers to sign up for capacity at Magnolia haven't changed. Nor has the advantage in gas pricing enjoyed in the US, where the abundance of gas close to pipelines ensures much cheaper prices than for LNG plants in Queensland for example.

He says customers are still looking long-term, wanting to secure access to US LNG exports no matter how unfavourable the economics look at present.
"Each of the parties we are talking to is still talking 20-year deals," Brand says.
Some hedge funds remain skeptical. One points in particular to Spain's Gas Natural Fenosa (GNF), which has provisionally agreed to take up to 2 million tonnes a year from Magnolia, a quarter of total capacity.
GNF has the option of buying LNG on the spot market, or taking capacity from a US exporter that is further down the development path and has spare capacity such as Cheniere Energy. Then there's the huge gas discovery that Italian oil major ENI has made off Egypt that Fenosa could access to revive its idled Damietta LNG plant in the country, the portfolio manager says.

With Magnolia targeted for financial close by March 2016, Brand has the next few months to silence the doubters.
amacdonald-smith@afr.com.au

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China’s slowing demand burns gas giants

• BRIAN SPEGELE
  
• THE WALL STREET JOURNAL
  
• OCTOBER 06, 2015 7:17AM
  

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Australia’s Arrow Energy typifies LNG projects whose economics have soured. Source: AFP
[b]The energy industry over-estimated just how much natural gas China needs, and global oil-and-gas companies risk paying a heavy price.[/b]
When China’s economy hummed along a few years ago, energy companies from Australia to Canada bet its demand for natural gas would grow fast. They spent billions of dollars on promising fields, with plans to freeze the gas into liquid, called LNG, and load it on tankers to sell to energy-starved Asian buyers at a premium.
China was “always seen as the kind of wonder market that was going to grow and need so much LNG,” said Howard Rogers of the Oxford Institute for Energy Studies and a former gas executive at BP PLC. “People got somewhat carried away.”
Recent data paints a grimmer picture. Chinese LNG imports are down 3.5 per cent this year, compared with a 10 per cent rise in 2014. Total gas consumption grew about 2 per cent in the first half, a turnabout from double-digit growth in recent years.
Natural gas is an extreme example of how China’s slowing economy has contributed to a global commodities crash. Producers of raw materials from aluminium to iron ore made heady bets on Chinese demand. So far, many are being proven wrong.
The downturn is sparking an industrywide recalibration. Energy consultancy Wood Mackenzie slashed its China gas-demand forecast by about 15 per cent to 360 billion cubic metres by 2020.
Globally, the market faces 25 million tonnes of LNG oversupply by 2018, says Citi Research — more than China imported all of last year. If all the projects being constructed, planned and proposed today came to fruition, the market would face around one-third more capacity than it needs by 2025, Citi estimates.
“We’re already seeing China cannot absorb all the gas that is thrown at it — that it’s choking on gas somewhat at the moment,” said Gavin Thompson, an analyst at Wood Mackenzie.
Northeast Asia spot LNG prices have fallen to less than $US8 per million metric British thermal units from over $US14 last fall, according to pricing agency Platts. US Henry Hub prices are under $US3 per mmBtu versus around $US4 a year ago.
Slowing demand could affect how North America develops as an energy-export hub. US gas exporters may have less of a market than hoped for, though their cheap gas should remain competitive. Some exports may head eastwards to Europe instead.
Depressed LNG demand follows the collapse in crude-oil prices that has shaken the energy industry to its core and added to global deflation fears. Natural gas, used in industry, power generation and transport, has been touted as the fuel of the future; gas is cleaner than oil and abundant in supply. The road bumps today show that transition will be far from smooth as key emerging markets intended to accelerate demand show weakness instead.
Several reasons explain China’s lacklustre LNG demand. Government-regulated gas prices are proving too expensive, sparking conflict between government and industry in some areas. Meanwhile bloated sectors are cutting capacity, which lowers energy needs. China is also importing more gas via Central Asia pipelines and has plans for big Russian shipments.
Australia’s Arrow Energy, a joint venture between Royal Dutch Shell PLC and state-controlled PetroChina, typifies LNG projects whose economics soured. The pair bought Arrow — which produces gas from underground coal seams — in 2010 for $3.5 billion planning to liquefy the gas for export.
But the Arrow venture lost about $1.5 billion last year, including an impairment charge of $700 million, amid what it called a poor “economic environment.” Shell announced this year it was shelving the planned export terminal.
Writedowns have stung others. The UK’s BG Group took a $US4.1 billion pretax charge on its huge LNG export facility in Australia due to lower oil-and-gas prices.
“The issue is: What kind of returns are we going be making on these projects now?” said OIES’s Mr Rogers. “Yes, these things have a 25-year-plus operating life, but you kind of want some nice cash flows during the first five to six years.”
Signs that China may buy less LNG emerged last year. In May 2014, China and Russia signed a massive gas-delivery deal which will eventually supply China some 38 billion cubic metres of gas annually — about 20 per cent of total Chinese demand last year. The countries are negotiating a second pipeline to bring even more Russian gas to China.
China wants to expand energy ties with its neighbours — including Turkmenistan and Kazakhstan — to curtail reliance on far-flung imports. Moscow and Beijing see mutual benefit in cooperation as Russia cuts dependence on shipments to Europe and China secures a large, new supply source.
Still, slack gas demand poses problems for Chinese companies. Sinopec Corp, the state-controlled refining giant, is contracted to take some 7.6 million tonnes of LNG annually from a project coming online later this year in Australia, called Australia Pacific, where it is invested with ConocoPhillips and Sydney-based Origin Energy. But with the Chinese market well supplied, Sinopec will likely be forced to sell some of that gas on the spot market, potentially for a loss, industry analysts say.
Sinopec said it would decide how to use Australia Pacific gas based on market conditions and the company’s needs. ConocoPhillips Chief Executive Officer Ryan Lance said the company was discussing with Sinopec how much gas it could take in the next two years.
No doubt, Chinese oil-and-gas demand will grow over time. The problem with stumbling demand now is that it hits energy companies’ profits just as they also struggle with low crude prices.
Lower Chinese gas demands are partly the result of government-regulated pricing that is discouraging its use. Despite falling prices globally, authorities have been slow to lower domestic gas tariffs.
When crude prices fell over the past year, petroleum-based products that compete with natural gas as fuels for industry got cheaper. Coal is also a cheaper option in China.
The reluctance of companies to pay more for LNG can be seen in Jinjiang, a city on China’s east coast that has made ceramics for centuries. Today, producers are locked in a dispute with authorities.
A government program designed to cut pollution ordered ceramics-makers to switch from coal to using natural gas. An LNG terminal nearby would supply the fuel.
But some companies reported production costs with gas were triple those of coal.
Business leaders have taken to the streets to protest. Wu Shengtuan, the 48-year-old chairman of a local building-tile maker, said his sales would slide roughly half this year, after suspending two production lines. He says he fears high gas prices could bankrupt Jinjiang ceramics-makers.
Lowering prices in the coming months — as many expect economic planners to do — would help. But lower demand also reflects a slowing Chinese economy.
“You always wanted to be able to count on China as a backstop because Chinese growth was always there,” said Mr Thompson, of Wood Mackenzie. “Companies are having to re-evaluate what the Chinese market ultimately offers.”
Wall Street Journal

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HSBC says low oil prices won't derail Australia's LNG boom
DateNovember 3, 2015 - 11:45PM

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Angela Macdonald-Smith
Energy Reporter

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Jean Francois Lambert, global head of commodities and structured trade finance at HSBC. Photo: Peter Braig

Weaker oil prices won't derail Australia's liquefied natural gas export boom and will give a lift to major economies such as China and Europe, according to the global head of commodities at the world's largest trade bank.
Jean-Francois Lambert, the London-based head of commodities and structured trade financing at HSBC, said that the success of shale oil in the US had changed the oil world, trapping prices within a band of between $US45 and $US55 a barrel for the next few years.
Should prices fall below the lower end of the price band, some production would become so unprofitable it is shut down, triggering a rebound. But once prices rise above $US55, US tight oil producers would "reopen the taps", dragging them down again.
"The oil price is hovering in a corridor," Mr Lambert said in an exclusive interview while in Sydney on Tuesday.
"That corridor is really the new normal until we have a very significant upsurge in demand and that will only be created by Europe waking up from its economic sleep."
The extended slump in oil prices has caused LNG prices to dive, calling into question the profitability of a $200 billion wave of new Australian export plants that are starting production.
But Mr Lambert said the producers would adapt to the lower prices, just as iron ore players have, optimising production and lowering costs, while the prospects for gas were still strong.
"I'm expecting as well that this industry will adapt to a new normal of the oil price," he said, at the same time acknowledging that it would take longer for producers to make a return on their investment.
"The world of energy is going to live on many legs: one of those legs will be natural gas. It is a key component."
Australia was "absolutely" still set to benefit as the country overtakes Qatar as the world's biggest LNG exporter, probably in 2018, and the plants would provide a long-lasting strategic advantage, Mr Lambert said.
HSBC, which processes $US1 million ($1.4 million) of trade turnover every minute, is forecasting that prices for West Texas Intermediate, the US benchmark, will average just $US55 next year, up from an estimate of $US49.80 this year. Brent is put at $US60 a barrel in 2016, up from $US55.40 this year.
Growth anticipated
The bank anticipates growth in Europe picking up slightly in 2016, partly due to cheaper energy, but Mr Lambert said it would likely take several years before growth jolted oil prices much higher.
Importantly, the benefits of cheaper energy and commodity prices in general would also be felt in China.
"The commodity price drop is benefiting China; it is going to be of benefit to the consumers, and to create some productivity," he said. "That should in turn create a better opportunity for China."
Mr Lambert described China as "the biggest questionmark in the world these days" but said the slowdown toward 6 per cent growth still meant it was "growing much much faster and creating more wealth" than 10 years ago when growth was in double digits.
"We are in the process of witnessing the creation of a very large developed economy; It's not there yet but it is in transition," Mr Lambert said. "It is entirely appropriate for a country like this to grow at a much more controllable pace."
Mr Lambert said the shift in China's economy from export-driven to consumer-driven was now joined by a third leg, infrastructure.
'Supercycle definitely over'
"Projects such as the One Belt One Road project are going to create tremendous infrastructure requirements in China and probably beyond China," he said, referring to China's grand-scale investment strategy for roads, ports and rail.
"All these give reason to be reasonably optimistic as far as commodity uptake."
Mr Lambert said while the "supercycle is definitely over" in commodities, China's imports of key commodities such as iron ore and copper were still on the rise, suggesting "we are now reaching the trough" in prices.
But he said the recovery would not be U-shaped, rather L-shaped, with just a gradual uptick "until a much stronger worldwide economy prevails."
The bank is forecasting a further slide in iron ore prices next year, to $US52 a tonne from $US58 this year.
But Mr Lambert said that at those prices, Australian producers were still profitable, benefiting from their success in lowering costs.
Thermal coal, however, faces a bleaker future, with the upcoming global climate talks in Paris set to underline dim prospects in power generation.
"Definitely I see more headwinds against coal than tailwinds," he said.