Japan’s Ichthys LNG targets late 2016 start-up in Australia
(Reuters; Aug. 7) - Progress on Inpex Corp.'s $34 billion Ichthys liquefied natural gas project in Australia is slightly behind schedule but is still on target to start commercial production by the end of 2016, the company said Aug. 7. Ichthys was 74 percent complete as of June, four or five percentage points behind target, but the project was still on budget, managing executive officer Masahiro Murayama told a news conference on its first-quarter earnings.
"It's delayed by about a quarter," he said. "To recover, we have been trying hard, adjusting various schedules and so on." With a number of new LNG projects coming online, Australia is on track to overtake Qatar as the world's top LNG supplier by the end of the decade. The Ichthys project, which will produce 8.4 million metric tons of LNG a year, will pipe gas off western Australia to an LNG plant near the coastal city of Darwin in Australia's Northern Territory.
Inpex, Japan's top oil and gas producer and 19 percent owned by the government, has a stake of more than 62 percent in the LNG project, with Total and several other Asian energy companies among the shareholders.
Report warns of damage to salmon habitat from LNG terminal in B.C.
(Globe and Mail; Canada; Aug. 6) - A study co-authored by six British Columbia First Nation groups warns that a proposed terminal for exporting liquefied natural gas on the province’s northern coast poses a threat to salmon habitat in the Skeena River estuary. The research argues Pacific NorthWest LNG’s planned terminal on Lelu Island will harm Flora Bank, where juvenile salmon are nurtured by eelgrass beds. Flora Bank, a sandy area that is visible at low tide, is next to the proposed LNG terminal near Prince Rupert.
The co-authors said their research found that if the project forges ahead, there would be damage to the ecosystem, including impacts on different spawning locations upriver. The findings are contained in a letter to be published Aug. 7 in the academic journal Science. “The Skeena watershed is united by salmon,” said the letter, signed by nine authors, including fisheries experts from six aboriginal groups. “First Nations throughout the watershed should be involved in decisions that could damage their fisheries.”
Jonathan Moore, a fisheries biologist who is an assistant professor at Simon Fraser University, is one of the co-authors, along with two members of the aboriginal-backed Skeena Fisheries Commission. “The Flora Bank region in the Skeena estuary is like Grand Central Station for salmon,” commission head scientist Allen Gottesfeld said in a news release. Pacific NorthWest LNG, led by Malaysia’s Petronas, is waiting for completion of a federal environmental review and further discussions with First Nations before committing to construction of the multibillion-dollar project to export LNG to Asia.
Canadian election likely to delay decision on LNG project in B.C.
(The Prince George Citizen; Aug. 5) - The early start on the federal election campaign has ended British Columbia’s hopes for getting an early start on a proposed liquefied natural gas terminal on the northwest coast. The Malaysian-backed Pacific NorthWest LNG project, proposed for Prince Rupert, B.C., still needs federal environmental approval. Even if the agency recommended that the federal cabinet approve the project, it likely would not be acted on until after the Oct. 19 election.
Though Environment Minister Leona Aglukkaq and her colleagues will continue to hold their posts until Oct. 19 — and maybe beyond that, depending on the will of the voters — in practice governments steer clear of such momentous decisions during the official campaign period. A change of government could mean additional delays, as the new cabinet decides whether to support the project and on what conditions.
The project also needs the go-ahead from the Lax Kw'alaams First Nation, as the proposed terminal site is within their traditional territory. Adding to the potential holdups, the Lax Kw'alaams are headed for an internal leadership election of their own this fall and may hold off approval until after that. All of which makes it likely that British Columbia is looking at late this year or early next for the much-sought-after "shovels in the ground" start on the project.
Columnist laments that delays jeopardize LNG industry in B.C.
(Vancouver Sun columnist; Aug. 7) - When B.C. Premier Christy Clark launched the plan to develop a liquefied natural gas industry four years ago, the province was not the only jurisdiction climbing on to the LNG export bandwagon. Just weeks before Clark made her big splash, Louisiana Gov. Bobby Jindal announced that Cheniere Energy would build “one of the first natural gas liquefaction facilities in North America” at Sabine Pass on the Gulf of Mexico.
Two months later, Clark pledged an “aggressive” drive to develop three LNG terminals by 2020, the first to be located in Kitimat and “fully operational by 2015.” Four years on, talk of having a terminal up and running by 2015 has long since fallen by the wayside. The Kitimat proposal, though still active, is no longer first in line. The project most likely to go ahead, proposed by Malaysia’s government-owned Petronas for a site near Prince Rupert, is still undergoing environmental review and First Nations consideration.
Meanwhile down in the bayou state, the first two production lines at Sabine Pass are scheduled to start up later this year. So while B.C. waits for somebody — anybody — to put the first shovels in the ground, Louisiana is poised to cross the finish line in the four-year quest to become a major exporter of LNG. Not to say B.C. doesn’t have significant advantages of distance to Asia and a rich supply of gas. Still, as Premier Clark herself said at the launch point of the LNG drive, “if we don’t fight for it, we could lose it.” We still could, through regulatory delay, litigation or environmental obstruction.
Oregon newspaper editorial criticizes FERC draft report on LNG site
(The Daily Astorian editorial; Aug. 6) - This week, the Federal Energy Regulatory Commission issued a draft report saying Oregon LNG’s proposed $6 billion terminal and pipeline project would harm the environment. But the typically pro-development FERC appears willing to be convinced that the project can be made safe enough to proceed. FERC’s analysis fails in several respects.
For example, FERC concludes that fishing boats forced out of the way by LNG tankers can simply return to what they were doing immediately after ships pass, without suffering any adverse effects. This assumption betrays a lack of understanding of how fishing boats operate. Significant interruptions are not so easily accommodated. FERC also appears to attach little importance to hazards associated with storing large quantities of LNG on a shoreline subject to subduction zone earthquakes and tsunamis.
The agency’s report concludes the project can be made to “provide acceptable layers of protection that would reduce the risk of a potentially hazardous scenario from developing into an event that could impact the off-site public.” This sounds all too much like the assurances of absolute safety made for Japan’s Fukushima Daiichi nuclear plants before an earthquake and tsunami turned them into a radioactive wasteland.
Texas coast water district opposes LNG terminals
(Port Isabel Press; Padre Island, Texas; Aug. 7) - During a special meeting Aug. 7, the Laguna Madre Water District on the Texas coast passed a resolution opposing the development and possible annexation of sites that several companies want to use for building liquefied natural gas export terminals along the Port of Brownsville. The water district is the first public entity to speak out against the proposed facilities.
Speaking after the meeting, Water District Chairman Jeff Keplinger said, “Personally, as one director, I can tell you that my constituents — the people I talk to — every single one of them is against it, except may one — one out of maybe 100 people I talk to.” He added, “I mean, I’m an elected official, I try to do what’s right for the community, and what the community believes in.”
Keplinger said that, as of yet, none of the LNG hopefuls have submitted an application for annexation and services. “But they did pick up an annexation packet, and they have been looking at that to see if they can be annexed into the water district,” he said. “We’re only a mile, a mile and a half away, as opposed to the Brownsville (utility service area) 20 miles away.” A Brownsville Utilities Board spokesman said the district would be unable to provide such services as the locations are outside its service territory.
Chile signs up for LNG from Cheniere’s Corpus Christi project
(Platts; Aug. 5) - Chile's Biobiogenera will import U.S. LNG to supply its Central El Campesino power plant at a landed price of $11 to $12 per million Btu, according to statements released Aug. 5 by the company. "It's a very competitive price in comparison with trucked gas or sporadic pipeline imports that come from Argentina," Executive Director Juan Jose Gana told Chile's Diario Financiero newspaper.
Central El Campesino plans to begin burning U.S. gas in 2019 under a 20-year supply and purchase agreement with Cheniere Marketing for 600,000 metric tons of LNG per year (averaging about 80 million cubic feet of gas per day) from Cheniere’s liquefaction plant and export terminal planned for Corpus Christi, Texas. The contracted gas will feed Central El Campesino's 640-megawatt, gas-fired combined-cycle power plant.
The imported LNG will be landed at a proposed floating LNG receiving and storage terminal in southcentral Chile. Before a final investment decision, the power plant and LNG import terminal must win regulatory and environmental approvals and financing.
Qatar succeeds at LNG with high volume, low cost
(New York Times; Aug. 5) – Liquefaction has reshaped the gas business, allowing the fuel to be pumped onto ships and dispatched around the world. And after investing tens of billions of dollars, Qatar is at the forefront. 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 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. ExxonMobil was the important early investor. Shell, Total and ConocoPhillips soon followed. 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 the LNG in the world.
“With the full development of Qatar, LNG came of age,” said Michael Stoppard, chief gas strategist at IHS, a research firm. “Qatar made LNG a bigger business — bigger projects, bigger ships, bigger volumes and a much bigger global footprint.” With the ability to produce and process such huge quantities of gas, Qatar keeps its costs low. IHS estimates it costs about $2 per million Btu to produce and liquefy gas in Qatar. The low-cost structure allows Qatar to be more nimble and make money even at low prices.
Investor Carl Icahn takes big stake in Cheniere Energy
(Bloomberg; Aug. 6) - Billionaire investor Carl Icahn is doubling down on energy after losing hundreds of millions of dollars in the sector this year amid the worst commodity price crash in a generation. Icahn on Aug. 6 reported a new 8.18 percent activist stake in Cheniere Energy and plans to seek talks with the liquefied natural gas exporter’s management and perhaps board seats “if appropriate.”
Shares of the LNG export plant developer are undervalued and Icahn will seek discussions on “operations, capital expenditures, financings and executive compensation,” according to a regulatory filing. In a potential showdown with Cheniere, which has lost money for at least 21 consecutive years, Icahn is training his sights on an innovative and little-known company that is set to become the first to export a bounty of gas from U.S. shale formations.
Icahn may also bring focus to Cheniere’s charismatic chief executive, Charif Souki, who drew fire last year after it was revealed that he received more than $140 million in 2013 compensation. Cheniere’s per-share value has jumped more than 30-fold from a low of $1.77 in 2009 to $65 as Souki moved to build the Sabine Pass liquefied natural gas terminal in Louisiana, which is expected to start shipments this quarter. The company is also building a second LNG export terminal, at Corpus Christi, Texas.
Greek shipping company will own five carriers serving Yamal LNG
(Lloyd’s List; Aug. 7) - Dynagas, the private liquefied natural gas shipping arm of the Greece-based George Prokopiou Group, is taking on five icebreaking LNG carriers to serve Russia’s Yamal LNG project. The 172,000-cubic-meter newbuilds of ice-class carriers were ordered from South Korea’s Daewoo Shipbuilding & Engineering by Yamal Trading as part of a 15-vessel fleet for delivering LNG from the Arctic project.
The five vessels were expected to have been owned by Russian flagship shipping company Sovcomflot, but financing has proved a problem. Lloyd’s List has been told that even for established western European or Asian ship owners, some banks have balked at what is seen as a “Russian risk.” Dynagas, though, is thought to have lined up funding for the vessels, which are worth a total of more than $1.5 billion.
Deliveries of the five carriers will begin in 2017. Other carriers to serve Yamal LNG will be owned by a consortium of Teekay LNG and China LNG Shipping, which will own six of the newbuilds, and Mitsui OSK Lines, together with China Shipping Development, which will have three. After the switch of five vessels to Dynagas, Sovcomflot will be left with one of the Yamal vessels, the first ship, which is scheduled to emerge next year.
Oil industry works to reduce costs for prolonged period of low prices
(Wall Street Journal; Aug. 5) - The world’s biggest oil companies have vowed to bring down the costs of big projects in the face of slumping oil prices, but the unrelenting price weakness — with crude below $50 a barrel — suggests they could have to dig deeper. In the past year, as prices plunged 60 percent from highs of $114 in 2014, BP began testing new projects for profitability around $60, down from $80 last year. Shell is testing projects at prices as low as $50, though its overall longer-term view is $70 to $110.
Billions of dollars less is being spent on everything from exploration and engineering to construction equipment and drill rigs. Last week, when the biggest oil companies reported quarterly earnings far lower than last year’s, chief executives said they would keep the pressure on spending as oil traded below even their new price assumptions. Some, such as Shell and Chevron, announced layoffs. “We don’t have a crystal ball but we are planning for a prolonged downturn,” said Shell CEO Ben van Beurden.
Focusing on lower-cost projects with higher returns will help, but companies are also relying on cost deflation for everything from drill rigs to pipelines, improved efficiency and increased standardization to help manage the low-price environment. “They are bringing down their costs both operationally and also in terms of capex, but it’s probably not going to be enough,” said Roberto Cominotto, investment manager at Swiss investor GAM, highlighting the need for a structural shift.
Despite low prices, U.S. companies continue to feed oil glut
(Wall Street Journal; Aug. 7) - Despite all their spending cutbacks and idle drilling rigs, U.S. energy producers are finding it hard to turn off the taps that have helped lead to a global glut of oil. Rising production was a major theme in the past week as shale drillers reported their second-quarter earnings. Devon Energy and Whiting Petroleum said they pulled record amounts of oil from the ground. Anadarko revealed that in some areas it has doubled the number of wells it can drill with a single rig.
Analysts say companies need to cut their output by at least 500,000 barrels a day to stem the oversupply that has sent oil prices tumbling over the past 14 months to just under $45 a barrel. But monthly oil production rose steadily through March, peaking at a record 9.7 million barrels a day that month and just slightly less in April, before edging down to 9.5 million barrels in May, according to the latest federal data. “We need to cut a whole lot more,” said Jamie Webster, a senior director at IHS Energy, a consultancy.
For oil production to fall that far, Webster said, the benchmark U.S. oil price will have to average $45 a barrel for at least six months. Roughly 200 drilling rigs — about a third the number working today — will also need to come out of the field by 2016. But companies keep finding ways to drill wells faster and cheaper in an effort to deal with oil that is selling for half the price it was a year ago. The easiest way for many producers to make up revenue lost to declining oil prices is to pump more.
Low oil prices could cost industry $4.4 trillion in the next three years
(Wall Street Journal; Aug. 7) – The world’s oil producers will forgo roughly $4.4 trillion in revenue over the next three years, based on the current outlook for prices and demand, relative to what was expected just a year ago. With Brent crude having tumbled back below $50 a barrel, the industry has entered a vicious, and spreading, bout of deflation.
A year ago, futures indicated an average Brent crude oil price in 2016 through 2018 of about $101 a barrel. Today, that is just under $60.
The implied hit to oil producers’ revenue is about $4.4 trillion spread across those three years. It is a crude metric that, for example, doesn’t take account of different grades of oil commanding different prices. But it does indicate the scale of the hit taken relative to expectations held only recently. Some 42 percent of implied revenue has disappeared.
This is why life is hard for companies trying to meet massive project and shareholder obligations — built up during years of triple-digit oil — with less cash flow. The same goes for exploration and production companies that built up debts in the shale boom. Oil producers’ desire to preserve margins means spreading the misery to oil-field services firms, which have seen equipment idled and pricing cut. Certainly, with Brent futures now priced under $70 as far out as the early 2020s, the market doesn’t see any relief.
B.C. economists say low oil prices could affect pipeline expansion
(Vancouver Sun; Aug. 4) - As Canada’s National Energy Board gears up to hear final arguments Aug. 24 into its embattled review of Kinder Morgan’s proposed expansion of its Trans Mountain Pipeline from Alberta to the B.C. coast, opposition is mounting as the price of oil drops, making the project less attractive. Local economists say that, barring a major war in the Middle East directly impacting top oil producers like Saudi Arabia, Canada’s oil sands might be in for a prolonged period of lower crude prices.
“The fact that the price of oil has fallen right now shouldn’t affect the decision of either the company or the regulator,” said Simon Fraser University energy economist Mark Jaccard, noting that pipeline decisions are usually based on projected revenues over 25 to 50 years. “However, if they believe that the price fall has a real long-term element to it, like we’re in a new world of oil prices for a decade or two, then it will affect the decision. … If prices stay really low, I don’t think (Trans Mountain) would go ahead.”
Kinder Morgan hopes to triple the capacity of the line by laying almost 625 miles of new pipe from Edmonton in the $5.4 billion project. James Brander, professor of strategy and business economics at the University of B.C.’s Sauder School of Business, agreed that lower prices could make the pipeline less attractive. “However, what really matters is the long-run trajectory in oil prices, not short-run changes in price. After all, oil would not start flowing in the new pipeline until 2018 at the earliest, and probably later.”
Sour gas forces shutdown of Canada’s Alliance Pipeline to Chicago
(Calgary Herald; Aug. 7) - An error that allowed sour gas to enter its main line has forced the closure of the Alliance Pipeline, preventing shipment of an average of 1.6 billion cubic feet per day of liquids-rich western Canadian natural gas to the Chicago area. Alliance closed down Aug. 7 and said will likely be closed through the weekend or longer. The tainted gas, which was stopped in southeastern Saskatchewan, is to be burned in flares at a compressor station. Flaring equipment was to be installed on site.
Tony Straquadine, manager of commercial and government affairs for Alliance, said there is no public health risk from the gas containing hydrogen sulphide — a poisonous, colourless gas with the foul odour of rotten eggs — as long as it stays in the system. He said flaring the gas is the safest way to dispose of it. “Our first priority is to safely manage the situation and protect the public, employees and the environment,” he said. Alliance runs 2,400 miles to a gas liquids plant and pipeline connections near Chicago.
The incident is a first for Alliance since it opened in 2000. The error was detected by monitoring equipment in the pipeline after the release was reported by the upstream source of the sour gas. Alliance didn’t identify the source but Calgary-based midstream company Keyera came clean in a news release reporting “a brief operational upset during maintenance” at its Simonette gas plant in northwestern Alberta on Aug. 5. The plant is designed to remove sulphur from up to 250 million cubic feet of sour gas a day.