Every $10 drop in oil could cost LNG developer $200 million
(Bloomberg; Aug. 19) – Share prices of Sydney-based Origin Energy fell the most in 15 years after the company turned to a full-year loss and said the plunge in oil prices could significantly reduce the income from its soon-to-start-up Australia Pacific LNG Project. Origin is a gas exploration and production company, in addition to its work as an electricity generator and retail gas and electricity distributor in Australia.
“Oil continues to weaken and there’s a broader concern in the market as to where does this end,” Origin managing director Grant King said. “At lower prices for longer … it’s going to be very difficult for everyone in the industry.” The downturn comes as Origin prepares to start its $24.7 billion (Australian) gas export project with ConocoPhillips on Australia’s East Coast. Should oil stay at current levels, earnings from LNG sales linked to oil prices will be significantly below expectations, Origin said.
Every drop in oil prices of $10 (Australian) per barrel would cut Origin’s share of cash from the LNG project by $200 million a year, the company said.
Low prices, weak market hammer Australia LNG developer
(Bloomberg; Aug. 20) - Oil’s collapse has claimed its latest victim. David Knox, CEO of Australia-based Santos, is stepping down amid a rout in energy markets, stoking speculation the company could become a takeover target. The oil and gas explorer has been approached by companies interested in “strategic opportunities” and is reviewing its options, Santos said Aug. 21 after posting an 82 percent drop in first-half profit. Its net debt of $8.8 billion (Australian) is well above its $5.7 billion market value.
Knox “has been burned by the oil price,” said Evan Lucas, market strategist at IG Ltd. in Melbourne. Oil’s plunge has punished explorers and shaken producers from Norway to Venezuela. “Underperforming companies that lose their leadership are the ones that get taken out,” said Neil Beveridge, an analyst at Sanford C. Bernstein & Co. in Hong Kong. “Santos pursued an overly aggressive growth strategy, and the fall in commodity prices has left them very exposed given the high levels of debt within their business.”
Santos had been counting on output from its share of the Papua New Guinea LNG project, which began exporting last year, and a late-September start-up for the Gladstone LNG project in Australia to boost its coffers, but weak oil-linked LNG prices have hammered its earnings. Gladstone, at $18.5 billion, is one of the world's first three coal-seam LNG projects, all in Australia's Queensland state and all starting up just as oil prices have sunk to 6½-year lows.
Drillers keep working in B.C., looking forward to LNG exports
(Vancouver Sun; Aug. 19) - Natural gas drilling in British Columbia’s Peace River region in the first half of 2015 fell by 23 percent compared with last year’s activity, although you wouldn’t know it by the amount of construction going on around the boom towns of Fort St. John and Dawson Creek. While drilling activity is down, companies are making up the difference by spending hundreds of millions of dollars to build pipelines, compressor stations and gas plants, continuing to look toward liquefied natural gas exports.
Despite the decline in drilling, activity levels in B.C. make the province a bright spot in Canada’s overall energy sector, which has been ravaged by plummeting oil prices. “B.C. is holding steady,” said Mark Salkeld, CEO of the Petroleum Services Association of Canada. “(Drilling activity) is not great compared to previous (years), but in this day, and all things considered, it’s pretty impressive.” Drillers punched 311 new gas wells in B.C. by the end of July this year, compared with 392 in the same months of 2014.
“There’s a reasonable amount of confidence that B.C. LNG initiatives will go ahead,” Salkeld said.
First Nation backs floating LNG plant in Vancouver Island inlet
(CTV News; Vancouver Island; Aug. 20) - A Vancouver Island First Nation has reached a deal for a proposed floating liquefied natural gas facility in the 15-mile-long Saanich Inlet at the southeastern end of the island. The floating plant, with up to 6 million metric tons per year of LNG-making capacity, would be moored to the shoreline of the Malahat-owned land formerly known as Bramberton, halfway down the inlet and about 20 miles northwest of Victoria.
The Malahat Nation announced the project in conjunction with representatives from Steelhead LNG, the Vancouver-based energy company that would build and operate the plant, at a news conference Aug. 20. Malahat’s acting chief Tommy Harry said the deal follows a push by the 319-member First Nation to explore economic opportunities after recently purchasing a 1,300-acre parcel of industrial-zoned land — the former site of a cement manufacturing facility. The land is currently being used as a rock quarry.
The facility would require construction of a pipeline from the B.C. mainland to supply the natural gas that would be liquefied and loaded onto tankers for export, according to Steelhead. Environmental assessments, financing and customers also are on the must-have list. Fran Hunt-Jinnouchi, a former director of the Office of Indigenous Affairs at the University of Victoria, said there were “lots of concerns” associated with an LNG plant in the Saanich Inlet. “Too risky, potentially disastrous,” she said.
Alberta oil sands service providers look to LNG projects for work
(The Financial Post; Canada; Aug. 11) - The camps around Fort McMurray, Alberta, catering to fly-in-fly-out oil sands workers while they’re away from home, have grown steadily quieter in recent months. As a result of thousands of oil-patch layoffs, companies that own and operate those camps, and similar hotel-like facilities in other once-busy oil fields, have been aggressively cutting their costs in an effort to keep a shrinking number of workers sleeping in their beds.
Now, however, the tantalizing potential of liquefied natural gas projects being built in British Columbia has executives looking past the oil-price downturn. “In terms of a catalyst for growth for our company, and I think even for the services sector here in Western Canada, I don’t know that there’s anything else other than a quick return to $100 oil that could have as big of an impact for us,” Black Diamond Group CEO Trevor Haynes said of the prospect for LNG projects on the B.C. coast.
“Are we excited? Yeah,” said Rod Graham, CEO of Horizon North Logistics. Supplying an LNG project would help offset the downward pressure the oil-price crash has put on camp providers. LNG Canada, led by Shell, confirmed it’s fielding proposals from would-be suppliers at its proposed project near Kitimat, B.C. Similarly, Malaysia’s state-owned Petronas is inching toward an investment decision on its LNG project near Prince Rupert and is also reportedly fielding proposals from camp providers and other services.
Chinese, Japanese firms team up to look at shale rocks in B.C.
(LNG World News; Aug. 19) – Japan Oil, Gas and Metals National Corp. and Japan’s largest oil and gas exploration and production company Inpex have commenced a joint study of technology for shale gas development in the Horn River, Liard and Cordova areas in British Columbia. The project is being carried out with Inpex Gas British Columbia and Nexen Energy, a unit of China National Offshore Oil Corp. (CNOOC).
The companies have entered into a joint-study agreement to evaluate geological characteristics of the areas by analyzing properties of rock samples extracted from shale reservoirs marked for development, the companies said in a statement. The data obtained in operations undertaken by Nexen and Inpex “will help optimize and streamline the development of shale gas reservoirs in the areas.”
The joint study is expected to continue for a period of approximately one year. JOGMEC is providing financial support for the project. Nexen and Inpex are partners in a proposed liquefied natural gas export project in British Columbia.
Analysts increasingly see oil possibly dropping into the $30s
(Wall Street Journal; Aug. 20) - As U.S. oil fell to a six-year low below $41 a barrel Aug. 19, an increasing number of analysts and traders are saying crude could drop into the $30s — and soon. The move to a price last seen in 2009 could come amid a seasonal fall-off in demand, coupled with concerns about China’s economy and the continuing global glut of crude. Cheaper oil would bring further joy to consumers and businesses around the globe, but more pain to others — from Russian officials to U.S. shale drillers.
It would also test the limits of oil storage facilities around the globe, which are already filling up. “Given where we are now, there is a 90 percent likelihood we will dip into the $30s,” said Chris Main, oil strategist at Citigroup. The market is also now preparing for millions of barrels of Iranian oil, after the nuclear deal struck between global powers and Tehran promised a lifting of some sanctions on Iranian oil. Most analysts still expect prices to bottom out soon and trudge toward $70 a barrel by the end of next year.
This year, however, Carsten Fritsch, senior commodity analyst at Commerzbank, said that the coming refinery maintenance season and worries over Chinese growth could easily push WTI into the $30 range in the coming months. Andrew Lipow, president of Houston-based consultancy Lipow Oil Associates, said that the pressure on oil will continue until next March as inventories build up with the maintenance season. Lipow has a price target of $32 to $34 a barrel for WTI in the next six months.
Refinery outages boost gasoline prices in California, Midwest
(Wall Street Journal; Aug. 24) - U.S. oil prices briefly dropped below $40 a barrel Aug. 21 — hitting a six-year low that adds to pressure on pump prices for Labor Day road trips. But cheap gasoline isn’t a sure bet everywhere. Even as most drivers around the country are spending 25 percent less than they did a year ago, California drivers have missed out on the windfall savings due to refinery outages. In Los Angeles, where a gallon of regular unleaded averages $3.71, some stations are at nearly $5 a gallon.
Production woes are spreading to other parts of the country, including the Midwest. That has kicked up prices in cities including Chicago, exposing how vulnerable some regions are to interruptions in fuel production. Refinery operators warn they must shut down big fuel-making factories from Illinois to Texas for several weeks this fall for needed repairs. “Gas prices are not as low as they should be because of unexpected problems at major refineries and strong demand from drivers,” said Michael Green, a AAA spokesman.
The national average for a gallon of regular unleaded was $2.60 a gallon this weekend — down from nearly $3.45 a year ago, according to AAA. Lower prices have spurred drivers to take to the road, burning more gasoline, and refineries have been operating at unprecedented rates to keep up. Last week U.S. refineries processed nearly 17 million barrels of crude every day — a 540,000-barrel jump over this time last year, according to federal statistics. As such, any interruption at refineries can have an outsize impact on prices, said John Auers, a refinery consultant at Turner, Mason & Co.
Alberta oil sands producers losing money at low prices
(Wall Street Journal; Aug. 20) - Canada’s high-cost oil sands producers are struggling as oil prices sink to fresh six-year lows, and even the most efficient drillers are losing money on every barrel they produce at current prices, according to a report published Aug. 19. Canadian oil sands production has grown 30 percent in the past five years but the recent price slump has hit producers’ bottom lines and forced them to suspend development of new projects.
Western Canadian heavy crude costs more to extract than other oil because it must be separated from deposits of sand. It also trades at a discount because of the distance it must be transported from remote boreal forests in Alberta. Benchmark West Texas Intermediate was at less than $41 a barrel Aug. 19, well above Western Canadian Select at $24. More than half of current oil sands production can’t break even unless WTI is above $44 a barrel, according to a TD Securities report published Aug. 19.
While about 45 percent of oil sands production comes from strip mines, the remainder is tapped via horizontally or vertically drilled wells. Operators pump steam into these wells to melt deposits of crude embedded in sand. At current low prices, there just isn’t enough money to cover the high costs. Despite lower prices, however, the Canadian Association of Petroleum Producers expects oil sands output to grow 30 percent through 2020 as multibillion-dollar projects already under construction start producing.
Norwegian Arctic oil field to start production in September
(Reuters; Aug. 19) - Italian energy group Eni plans to start oil production from Norway's first Arctic oil development in a few weeks after two years of delays and cost overruns. Production from the Goliat field, estimated to hold about 174 million barrels of oil, was originally expected to start in 2013.
"We had some delays due to bad weather, but we are planning to start production in a few weeks," said Andreas Wulff, spokesman for Eni in Norway. When the field comes on stream, it will become the world's northernmost producing offshore oilfield, Eni has said. The oil will be stored on a floating production platform and offloaded to shuttle tankers for export, while the associated gas will be reinjected.
Production from the field, some 32 miles southeast of Norway’s Snoehvit field, which delivers gas to Europe's only liquefied natural gas plant at Hammerfest, is expected to peak at some 34 million barrels of oil per year during the second year of production, the company said. Project costs surged to 46.7 billion crowns ($5.62 billion) from an original estimate of 30 billion crowns in 2009, when the development was approved. Operator Eni has a 65 percent stake in the field, while Norway’s Statoil holds 35 percent.
Canada’s largest refinery favors cheaper imports over Bakken by rail
(Wall Street Journal; Aug. 20) – The operator of Canada’s largest oil refinery, Irving Oil, said it has stopped importing Bakken Shale oil in favor of cheaper crudes from such producers as Saudi Arabia, reflecting a shift in crude costs affecting East Coast refiners during the global oil slump. Irving’s 320,000-barrel-a-day refinery in Saint John, New Brunswick, has cut purchases of U.S. Bakken crude shipped by rail to zero from a high of nearly 100,000 barrels a day two years ago, President Ian Whitcomb said Aug. 20.
The move reflects shifting economics in the energy industry even as the price of oil — including Bakken crude — has slumped to six-year lows. A once-yawning gap between the cost of oil produced in North America and overseas crudes priced at the Brent global benchmark has narrowed since 2013. Refiners on North America’s East Coast can now import crude shipped by sea for less than the cost of shipping it by rail from shale oil producers in North Dakota and elsewhere in the U.S.
U.S. shale oil production has surged, especially from North Dakota, where a lack of pipelines led to a boom in shipments by rail. Shipping by rail is more expensive and fewer refiners seem willing to pay that premium. The number of railcars carrying oil has dropped sharply from last year, reflecting the worsening economics of crude-by-rail and better pipeline access to Gulf Coast refineries. The Association of American Railroads said earlier this month that oil traffic was down almost 20 percent from its 2014 peak.
Local residents speak out against Texas coast LNG projects
(Environment & Energy News; Aug. 21) - Sandwiched between the Bahia Grande wetlands and the Las Palomas Wildlife Management Area at the southern tip of Texas lies the Brownsville Ship Channel, a narrow 17-mile waterway carrying traffic in and out of the Port of Brownsville. There, plans to develop several liquefied natural gas export terminals are drawing intense scrutiny as locals weigh jobs and investments against disruption to habitats and viewsheds in one of the Texas coastline's few pristine areas.
Five developers have proposed LNG export plans at greenfield sites along the channel, which lies just a few miles from the Mexico border and boasts deepwater ship access and proximity to key Texas natural gas plays. Three projects — Annova LNG, majority-owned by electricity generation and utility giant Exelon; Rio Grande LNG, owned by Texas-based LNG developer NextDecade; and privately owned Texas LNG — started pre-filing procedures with the Federal Energy Regulatory Commission this year.
At a FERC "scoping meeting" this month, comments poured in as local residents raised concerns about the plans. "This is one of the biggest stretches of undeveloped coastal habitat" in the state, said Stefanie Herweck, a volunteer with the group Save RGV from LNG, which represents communities throughout the Rio Grande Valley. Critics are concerned the plants would cause irreparable harm to native habitat and change the character of an area known for birdwatching and saltwater fishing.