Australia LNG industry prepares for fights over cost overruns
(Australian Financial Review; July 6) - Australia's liquefied natural gas sector is set to be swamped by a wave of disputes between producers and contractors over liability for cost overruns and delays, as the slump in commodity prices sharpens appetites to claw back funds. Chevron's over-budget $54 billion (U.S.) Gorgon LNG venture, Santos' $18.5 billion Gladstone LNG project and Inpex Corp. $34 billion Ichthys project in Darwin are among those understood to be the subject of arguments over responsibility for contract variations that have had an impact on the entire supply chain.
"The numbers are mind blowing," said Owain Stone, a forensic expert at Australia-based advisory firm KordaMentha. But Kevin Berg, general manager at Gladstone for Bechtel, the U.S. contractor building all three of the Queensland LNG plants as well as Chevron's Wheatstone project in Western Australia, played down the claims. "As is typical on all major projects of this scale, many closeout activities are in progress as we move closer to completion and handover of assets to our customers," Berg said.
It's standard practice for parties in big infrastructure projects to set aside money for cost overruns. What makes the LNG sector unique is the magnitude of the sums. Law and accounting firms look to be the big winners of wrangles between producers, contractors and subcontractors over liability for changes to work orders that have in some cases pushed projects billions of dollars over budget. One legal source pointed to three claims each involving more than $1 billion and others in the hundreds of millions of dollars.
Smaller B.C. LNG project continues toward investment decision
(Vancouver Sun; July 1) - Outside the higher-profile news of Malaysia’s Petronas and its liquefied natural gas proposal for Prince Rupert, B.C., along with gloomy forecasts for the sector’s prospects, AltaGas continues working away on its own smaller proposals. Calgary-based AltaGas anticipates it will be able to make a final investment decision before the end of the year on the relatively modest Douglas Channel LNG proposal at Kitimat, B.C. Its bigger Triton project remains a bit on the back burner.
Weak global prices, fear of a supply glut, and provincial and First Nations issues have slowed down the drive toward establishing an LNG export industry in B.C. “We’re still doing work on (Triton) in the background,” said Dan Woznow, AltaGas vice president of energy exports. “It’s just not our main focus.” The mid-sized Triton project would be capable of producing 2.3 million metric tons of LNG per year, more than four times the size of the Douglas Channel project, yet one-fifth the size of the initial Petronas project.
Douglas Channel LNG, which AltaGas signed on to earlier this year as part of a bid to take it out of creditor protection, is simpler to put together, Woznow said. The project is a consortium that also involves Japanese energy firm Idemitsu Kosan, French utility firm EDFT Trading and Belgian LNG tanker owner Exmar. The project is designed to use excess capacity in the existing Pacific Northern Gas pipeline to Kitimat with a barge-based liquefaction plant that is small enough to not require a full environmental assessment, Woznow said. Triton, on the other hand, would require its own pipeline.
Consultancy says Turkey a good market for U.S. LNG
(Global Trade; July 5) - The complicated pricing of natural gas in global markets, with a myriad of long-term and short-term arrangements, sometimes linking gas deals with oil pricing, together with the dynamic demand picture for natural gas and the robust build-out globally of liquefied natural gas infrastructure all combine to make Turkey the prime target for U.S. LNG exports. That was one of the conclusions reached in a recently-released report from the consultancy Energy Mining Advisory Partnership of London.
The report determined that U.S. LNG would have a tough time competing for market share in many countries while oil prices stay down. But Turkey is a different story. Turkey has experienced the fastest growth in energy demand of the OECD countries over the past three years. Domestic production fills less than 10 percent of Turkey’s energy demand. The country’s energy mix has moved strongly toward natural gas, overtaking oil consumption in 2012.
Turkey currently receives gas from Russia and Iran by pipeline under long-term contracts at relatively high prices. Additionally, Turkey’s commercial relations with those two countries are strained due to the penalties it has had to pay under its onerous contracts. Turkey could buy U.S. gas has at prices 40 percent below what it currently pays to Russia and Iran. With Turkey’s deals with Russia and Iran up for renewal in 2021, U.S. LNG exports could help Turkey negotiate better deals with Iran and Russia.
Spot-market price in Asia moves higher, to $7.55
(Reuters; July 3) - Asian liquefied natural gas spot prices for August delivery rose July 3, with a pick-up in activity driven by trading houses and portfolio players maneuvering volumes between the competitively priced Atlantic and Pacific basins. The price of Asian spot cargoes rose to $7.55 per Btu, from $7.30 the previous week.
"It's not a particular shift in end-user demand or producer supply, it's not like suddenly the significant Japanese, Korean, Chinese end-users have unveiled new demand, it's not that, but we do have ongoing tenders,” with some cargo movement, a trader said.
On the supply side, the market’s newest addition, Indonesia's Donggi Senoro LNG export plant, which began ramping up last month, has sold its first cargo to state-run company Pertamina's Arun import terminal for delivery in late July or early August. The single-train plant plans to produce 13 cargoes this year, six of which will go to buyers such as Japanese trader Mitsubishi and utility Kyushu Electric as well as Korea Gas, while six cargoes will be earmarked for spot markets.
Proposed Mississippi LNG export plant starts process with FERC
(Sun Herald; Gulfport, MS; July 4) - Owners of Gulf LNG, which owns the two huge storage tanks that dominate the horizon southeast of Pascagoula, Miss., say the facility could become the largest economic development investment in the state's history. The owners have proposed spending $8 billion to build a liquefied natural gas export terminal at the site of the underused import facility that opened in 2011.
Gulf LNG last month took the next step in the process when it formally applied to the Federal Energy Regulatory Commission for an environmental assessment. Economic development leaders in industry-savvy Jackson County are "cautiously optimistic." George Freeland, director of the Jackson County Economic Development Foundation, cautioned, “It’s important to manage expectations here. … The business model has not come together yet." The export project lacks customers, he said.
In order to make such an investment, Gulf LNG must line up customers, and that involves competing with three dozen other proposed U.S. LNG export projects also seeking federal approval to export. For Gulf LNG, just entering the FERC process is a major commitment. Gulf LNG Holdings is owned 50 percent by Southern Gulf LNG, whose parent company is pipeline giant Kinder Morgan. In addition to FERC approval, the project also needs export approval from the U.S. Department of Energy.
Shell orders three more floating LNG production vessels
(Business Korea; July 2) – South Korea’s Samsung Heavy Industries has won almost all of the recent orders to build floating LNG production vessels. Samsung announced July 1 it has won three orders for FLNG vessels from Shell at 5.27 trillion won ($4.7 billion U.S.). FLNG facilities are offshore plants designed to extract and refine gas from undersea fields and process and store it as LNG. They are the world’s largest maritime vessels.
This year to date, six FLNG vessels have been ordered in the global market, and Samsung won contracts to build five of them. Three FLNG ships from Samsung will operate in the offshore Browse fields, 265 miles northeast of Broome, Australia. The fields are thought to contain 15 trillion cubic feet of gas and 450 million barrels of condensate. The vessels built for Shell will be 1,600 feet long, the same size as the first FLNG vessel for Shell currently nearing completion at Samsung.
The recent shipbuilding contracts are only for the hull construction; a contract for the topsides and equipment for the vessels will be signed in the second half of 2016. Also, the contracts are conditional upon issuance of the notice to proceed. Shell said the latest vessels could be ready for work in 2023.
Turret mooring system finished for Shell’s floating LNG vessel
(Arabian Supply Chain; July 5) – United Arab Emirates-based Drydocks World has successfully completed the world’s largest turret mooring system for SBM Offshore, Technip and Shell. At almost 328 feet high and weighing more than 11,000 tons, the 85-foot-diameter turret will ensure that Shell’s Prelude floating liquefied natural gas production and storage vessel can operate safely in extreme weather conditions.
At more than 1,600 feet long, Prelude is the largest vessel ever constructed. Shell plans to park the vessel offshore Australia, to produce gas, liquefy it and store it for tankers to load up and deliver the fuel to customers worldwide. Prelude is scheduled to go to work in 2016. The turret mooring system, which is built into the structure to allow the vessel to remain in operation as it turns in the seas and winds, was designed in Monaco, constructed in Dubai and shipped to South Korea for installation on Prelude.
Prelude is under construction at the Geoje yard in South Korea and now has its topside modules installed. The three modules at the heart of the liquefaction process house the two large refrigerant compressors, the main cryogenic heat exchanger and the three cryogenic pre-coolers. Two modules contain the fractionation and natural gas booster compressor units. They also host the four fractionation columns, reboilers, pumps and vessels that separate the natural gas into methane, ethane, propane and butane.
Small oil producers step up for opportunities in down market
(Bloomberg; June 30) - Crude oil’s plunge is leaving drilling rigs idle from Africa to Latin America as the world’s biggest energy companies curtail spending and stall projects. Their smaller rivals, however, are seizing the opportunity to gain ground. Sound Oil, a Mediterranean producer one-500th the size of Italy’s Eni, will start exploring fields in Morocco and Italy toward the end of 2015 and early 2016, while Cairn Energy and Savannah Petroleum plan wells in West Africa.
“Large companies have dividend and debt burdens to be taken into account when oil prices decline and their response time is slower,” Sound Oil CEO James Parsons said. “Smaller explorers are quick to use the opportunity of declining costs and increasing availability of rigs.” Drilling fees have dropped by about half in the past year, prompting junior oil companies to lock in contracts before rates rebound.
While smaller fields can be profitable for a small producer, they’re of little interest to larger rivals that need a higher rate of return. Rig costs typically react to oil with a lag of about six months, so today’s drilling rig contracts reflect prices that sank to almost a seven-year low in January, forcing major producers to defer almost $200 billion of megaprojects. By steering clear of costly developments such as oil sands and deep-water deposits, the juniors can profit from current prices at about $60 a barrel.
Banks could tighten credit on oil and gas producers
(Wall Street Journal; July 3) - U.S. regulators are sounding the alarm about banks’ exposure to oil-and-gas producers, a move that could limit lending to companies hit by a year-long slump in prices. The Federal Reserve, Office of the Comptroller of the Currency and Federal Deposit Insurance Corp. are telling banks that a large number of loans to these companies are substandard, said people familiar with the matter, as they issue preliminary results of a joint national examination of major loan portfolios.
The substandard designation indicates regulators doubt a borrower’s ability to repay or question the value of the loan’s collateral. The designation typically limits banks’ ability to extend additional credit to the borrowers. The move could add an extra obstacle to companies struggling with high debt loads amid low oil and gas prices. Banks have been flexible with troubled energy companies to avoid triggering a flood of defaults and bankruptcy filings, but regulatory pressure could force them to tighten the purse strings.
Twice a year, banks themselves review the value of oil and gas deposits that companies have the right to extract and use as collateral for bank loans. Declines in commodity prices can prompt lenders to reduce their commitments to companies. The effects of such reductions can cascade through energy companies’ capital structures and require them to look elsewhere for funds.