Condensate production helps economics at Australian LNG projects
(Reuters; June 22) - Australia is in the pole position to capture a bigger piece of the growing Asian condensate market, with producers pumping new supplies of the ultra-light oil as natural gas output soars to feed the nation's mega-LNG projects. An Australian wave of liquefied natural gas supply has helped pull Asian LNG prices down by 75 percent since 2014, so selling more lucrative condensate to Asian buyers could give a lifeline to less profitable gas projects.
Australia's $37 billion Ichthys LNG export project, for instance, developed by Japan's Inpex Corp., could produce more than 100,000 barrels per day of condensate when it starts up next year. "The fact that the project is liquid-rich is one of the reasons that this project is economically in good standing," an Inpex spokesman said, adding that the company has started marketing its condensate, primarily to customers in Asia.
Condensate is a light oil produced in association with gas, and its consumption is rising across Asia as new refineries or splitters come online to meet strong demand for it to make the chemical feedstock naphtha. Besides Inpex, Chevron plans to produce 38,000 barrels per day of condensate once it ramps up its Gorgon LNG project on Barrow Island off the northwest coast of Western Australia. The circle of condensate suppliers is small, though, and Australia has the inside track on selling to Asia.
Advisory firm warns Australia needs more markets for its LNG
(The Gladstone Observer; Australia; June 22) - Despite the massive increase in LNG production, which will see Australia rival the world’s biggest producer Qatar in the near future, Australian LNG companies aren’t getting much bang for their buck. With the three plants on Curtis Island ramping up and coming into full swing, production has increased 53.2 percent on the last quarter, but because of the huge drop in prices export revenue in the first quarter of 2016 dropped 1.9 percent to $4.47 billion.
Given that the worldwide LNG glut is expected to hang around until the middle of the next decade, and that Australia’s major importers Japan and Korea signaling a drop in demand, things could get a little bit tricky. In March, the average Japanese import price of Australian LNG fell to $7.28 per million Btu, down from $12.73 at the same time last year. With Australia’s biggest importers slowing down on consumption, EnergyQuest’s quarterly report suggested this forces "emphasis on the need for new markets.”
EnergyQuest is an Australia-based energy advisory firm. "In addition to Egypt, there are a further eight countries in Africa considering LNG imports, including South Africa. … Demand is also growing in South America." However, the report found the opening of new markets would not be large enough or develop quickly enough to have a material impact on the current LNG glut.
Texas community divided over LNG export projects
(San Antonio Express-News; June 19) - Not long after a deadly refinery explosion left her husband battered and traumatized, Flora Gundersen, 67, decided she could no longer bear the smokestacks and flares on the horizon. So the couple relocated to Long Island Village on the coastal waters near South Padre Island, Texas. The couple had envisioned a retirement of leisurely fishing trips and golf in a subtropical paradise, and for most of the past decade that was pretty much how life went for the Gundersens.
Now a proposal to build facilities for the liquefaction and export of natural gas, all within sight of their back porch, has raised the specter of an industry they hoped to leave far behind. “They’re going to turn our pristine waterway into the same thing as Texas City,” Flora said. “That’s not something we want to be a part of.” The Gundersens are not alone in their angst. A growing number of residents and elected officials in Cameron County have resisted the three LNG proposals for the Brownsville Ship Channel, citing safety and environmental concerns, as well as fears the industry could scare off tourists.
The projects, however, have drawn broad support from the Rio Grande Valley business community on promises the industry will create jobs and infuse the region with billions of dollars of investment. If a rising chorus of critics doesn’t derail the Brownsville projects, convincing the Federal Energy Regulatory Commission that several export terminals are necessary in an already saturated global LNG market could. FERC in March rejected plans for an export terminal in Coos Bay, Ore., after it determined that the applicant had not demonstrated a market need for the facility or its product.
First Nations continue fight against Petronas-led LNG project in B.C.
(Globe and Mail; Canada; June 19) - Two First Nations leaders in British Columbia — fighting a proposed liquefied natural gas plant near Prince Rupert — say Ottawa needs to recognize the hereditary rights of the Allied Tsimshian Tribes of Lax Kw’alaams. Donnie Wesley and Ken Lawson say Pacific NorthWest LNG’s plan to build a plant on Lelu Island poses a threat to salmon habitat. The two men are hereditary leaders of the Gitwilgyoots, one of nine allied tribes of the Lax Kw’alaams in northwestern B.C.
“This area sustains not only our food resources but is the heart of Tsimshian culture and society,” they said in a letter this month to Canadian Prime Minister Justin Trudeau. “For us, this is not a matter of jobs and money, but goes to the very survival of our grandchildren, great grandchildren and those yet unborn. That is what we must consider and that is our law.” Wesley and Lawson lead a group of indigenous people who have occupied Lelu Island in rotating shifts since last August.
“We intend to pursue all available options to protect our aboriginal rights and titles in our territories, including the Prince Rupert harbor area and adjacent waters,” said the letter sent to Trudeau and five federal Cabinet ministers. The letter is the latest salvo fired by critics of Pacific NorthWest LNG, a consortium led by Malaysia’s state-owned Petronas. The project is waiting on a decision on its application from the Canadian Environmental Assessment Agency, expected this fall, and then a federal Cabinet decision.
Expanded pipeline capacity will deliver more U.S. shale gas to Mexico
(Bloomberg; June 20) - In two years, pipeline giant Enterprise Products Partners will be capable of processing 800 million cubic feet of gas a day in an energy-rich stretch of West Texas and southeastern New Mexico known as the Delaware Basin — 20 times what it could handle in 2012. Behind this rapid expansion is a big bet on Mexico. Once Enterprise removes liquids from the gas, the fuel will flow into pipelines delivering to the southerly neighbor, among other places, Enterprise spokesman Rick Rainey said.
Enterprise is “going to serve the burgeoning demand for natural gas in Mexico,” said Ed Hirs, an energy economist at the University of Houston. "They are staking a claim to the market." The Houston-based company won’t be the only one. Spectra Energy, Sempra Energy and TransCanada are also involved in multibillion-dollar pipeline projects that will help bring more shale gas to Mexico, creating a new outlet for the glut of supply that has been pooling up in the U.S.
Their investments are proof of the shift in Mexico’s energy industry since the country opened markets to private spending in 2013. Enterprise’s expansion includes a new gas-processing plant, though Enterprise has yet to decide where to build the plant that will handle 300 million cubic feet a day. It is the third gas-processing complex of its kind that Enterprise has announced in less than two years. U.S. gas exports to Mexico are set to increase because of growing power demand and flat gas production in Mexico.
Egypt expects to import at least 110 LNG cargoes next year
(Reuters; June 19) - Egypt aims to import between 110 and 120 cargos of liquefied natural gas in 2017, the state-owned Egyptian Natural Gas Holding Co. told Reuters on June 19. Egypt relies to a large extent on LNG to generate electricity for its 90 million people. Once an energy exporter, Egypt has turned into a net importer because of declining oil and gas production and increasing consumption. It is trying to speed up production at recently discovered gas reserves to fill its energy gap. Meanwhile, its LNG export plants that opened in 2005 have mostly gone silent.
Russia ready to battle U.S. LNG for market share in Europe
(Reuters; June 22) – U.S. liquefied natural gas is set to do battle in Europe, but Russia's Gazprom is preparing a cold reception for the super-cooled gas set to cross the Atlantic. A weakened ruble has lowered Gazprom's production costs by a fifth while its profits on dollar-denominated gas sales to Europe last year doubled in ruble terms. Gazprom has managed to increase its sales despite a push by the European Union to curb Russian energy imports, offering discounts, renegotiation of contracts and gas sales at auctions.
Spurring Gazprom's charm offensive is a looming showdown as a wave of U.S. gas is set to reach Europe's shores beginning next year. That threatens to exacerbate an already significant global oversupply, with new producers squaring up against established players for market share and driving prices lower. "We are at the start of a new chapter in European gas markets," said Fatih Birol, executive director at the International Energy Agency, as U.S. and other suppliers fight to gain access.
Gazprom appears confident it can fight off the challenge and even raise its European market share, which stood at 31 percent in 2015, helped by declining output in Europe, primarily in the Netherlands and Britain. "Russian gas is low cost and will remain below U.S. gas prices," said Claudio Descalzi, chief executive of Ital's Eni, the biggest buyer of Russian gas in Europe. As much as half the production capacity of U.S. LNG players could be shut-in during the summer and at other times if Gazprom simply keeps flowing gas to Europe at current rates, said Stephen O'Rourke at consultancy Wood Mackenzie.
Larger U.S. oil independents ‘trying to get back in the game’
(Reuters; June 20) - Two years into the worst oil price rout in a generation, large- and mid-sized U.S. independent producers are surviving and eyeing growth again as oil nears $50 a barrel, confounding OPEC and Saudi Arabia with their resiliency. That shale giants Hess, Apache and more than 25 other companies have beaten back OPEC's attempt to sideline them would have been unthinkable just months ago, when oil skidded to $26 a barrel and corporate collapses were feared.
The pain was acute. Industry revenue fell more than 30 percent from 2014 to 2015, the U.S. drilling rig count dropped by more than 70 percent from when oil was above $100 per barrel, stock valuations plunged and scores of small producers went bankrupt. But so far no U.S. producer that pumps more than 100,000 barrels per day has gone bankrupt. The survival of these big producers partly explains why U.S. production has slipped only about 10 percent since peaking at 9.69 million barrels a day.
Their agility — which required slashing costs in half while doubling down on improved techniques to squeeze more oil from each new well — is now allowing the industry to cautiously focus on growth again. But this time, U.S. producers say they will stay focused on capital returns, having abandoned a culture of maximizing production regardless of costs. "People are not necessarily freaking out anymore," said Sam Xu, an investment banker with CohnReznick Capital Market Securities. "Instead of trying to keep their heads above the water, they're now trying to get back in the game."
Anadarko CEO says $60 oil needed to restart shale production growth
(E&P magazine; June 21) - Although the price for West Texas Intermediate crude has slowly rebounded from a low point of about $27 per barrel, prices must surpass $60 for U.S. shale production to begin growing again, Anadarko CEO Al Walker said. Walker said a lower price could mean the industry, especially those in capital-intensive shale plays, will not have enough cash flow to flourish or sustain growth. Walker made his comments June 21 at the Wells Fargo West Coast Energy Conference.
However, a $50 to $55 oil price might have “good wellhead economics,” bringing an internal rate of return of 25 percent to 30 percent, he said. Oil and gas companies worldwide have seen their profits fall due to lower commodity prices, the result of too much oil and gas with not enough places to go. To make financial ends meet, companies have been cutting costs by delaying or scrapping projects, selling noncore assets, reducing staff and other measures. But higher prices still are needed.
At $80, for example, “we might be able to develop a shale field in less than three years to free cash flow. At $50 to $55, it’s going to take us five, six [or] seven years, if we stay within cash flow with our capital expenditures,” Walker said. Among the other caveats: cost efficiencies since the downturn’s onset must be maintained. And despite becoming more efficient, $50 to $55 oil does not enable companies generate cash fast enough to quickly reinvest in fields. That means the ramp-up to growth will be slower, he said.
Alberta oil sands producers look for cleaner technology
(Bloomberg; June 14) – Harbir Chhina, now a top exec at Cenovus Energy, one of Alberta’s oil sands producers, years ago helped develop the game-changing steam technology that allowed companies to tap the world’s third-largest oil reserves. It was a moonshot that paid off. Now the industry, still recovering from last month’s wildfires, needs another one. Without a technological breakthrough like steam injection in the 1980s, the flows that have transformed the region’s economy could slow to a trickle.
In a world that has plenty of cheap crude, and increasingly demands cleaner energy, the oil sands look dirty — and expensive. But Chhina said he is as optimistic as he was in the 1980s, when the oil sands began to take off. Cenovus CEO Brian Ferguson said he aspires to eliminate the carbon from producing a barrel of oil. Chhina and his colleagues are making a start, experimenting with simpler ways of melting the nearly solid bitumen buried under Canada’s boreal forest.
Solvents like butanes are currently the likeliest candidates, though microwaves are an intriguing alternative. Researchers are testing a technology that would fire the waves into horizontal boreholes to heat the bitumen, like food, without affecting the rock and sand. Another oil sands giant, Canadian Natural Resources, is looking at ways of harnessing the carbon dioxide and heat from its operations. They’re channeled into large tanks of treated wastewater, where they help grow algae under LED lights. The goal is a bio-refinery whose output could have various uses, from diluent to animal feed.