Gazprom squeezed by falling prices and production
(Bloomberg columnist; July 30) - Mismanagement and politically driven expansion are catching up with Russia’s state-owned gas company Gazprom. Output this year is forecast to be the lowest in its history, pipeline projects are floundering and it's not doing well in Europe, its key market. In June 2008, when Gazprom's market value reached $360 billion, CEO Alexei Miller predicted it would be the world's biggest enterprise, worth $1 trillion, in seven or eight years. He was wrong; Gazprom is worth $55 billion.
The Russian economics ministry predicted this week that Gazprom's output would drop to 14.6 trillion cubic feet of gas this year, lower than ever and one-third below capacity. The company had been counting on growth in both domestic consumption and exports. But the former has slumped because of Russia's recession, and the latter has shrunk because Europe, Gazprom's biggest export market, has diversified its energy sources. In 2014, Gazprom's exports were 3.2 tcf lower than in 2008.
The Russian business daily Vedomosti estimated that Gazprom, under Miller, may have spent $40 billion on unneeded expansion. He may have done this to benefit Gazprom's billionaire contractors, friends of President Vladimir Putin. The company is still a cash cow — last year, 9 percent of Russian government revenue came from Gazprom — but it appears strategically challenged, squeezed from all sides by dropping prices, falling demand, unfriendly regulators and politicians suspicious of Putin and his friends.
The economic slowdown in China, meanwhile, is undermining Gazprom's grand, costly diversification plans. The company has already scrapped a liquefied gas project in the Russian Far East, which was meant for the Chinese market. Its plans for the Altai pipeline to China, tentatively announced this year, were delayed indefinitely this month (although another pipeline to China, agreed to in May 2014, is still in the works).
Shell says floating LNG project in Australia could be delayed
(Sydney Morning Herald; July 30) - Shell has signalled that a go-ahead next year for the Browse floating liquefied natural gas project in Western Australia is far from a certainty given the cost challenges of the venture in the depressed oil-price environment. Shell’s chief financial officer Simon Henry listed Browse among several large projects that would be subject to "the dynamic nature of decision making as we take both the oil price environment but also the supply chain and the cost level into account."
"There are some quite large investment decisions in the next 18 months that are on the table but only if we get the right returns and cost levels," Henry told journalists on a teleconference on Shell's second-quarter results. Shell announced July 30 that it would slash capital investment by $7 billion as it buckles down for a drawn-out weakness in oil prices. The cutbacks are heightening concerns about the prospects for its Australian gas investments particularly after its proposed $70 billion takeover of BG Group.
Woodside Petroleum, operator of the Browse project, is aiming for a final investment decision on the venture in the second half of 2016. Woodside CEO Peter Coleman said in April he now expected returns from Browse to be at the lower end of the company's 12 to 15 percent target range for new projects.
Oregon LNG project loses court case against Army Corps
(The Daily Astorian; OR; Aug. 1) - A federal judge has ruled that Oregon LNG’s challenge to an Army Corps of Engineers easement on the Skipanon Peninsula in Warrenton came too late. Oregon LNG claimed the Army Corps, which has held an easement to deposit dredging spoils since 1957, has no right to land beneath the water that the company intends to use for an LNG export terminal. The company also wanted the court to declare the company has the right to access the property across tidelands.
But the judge ruled July 28 that the lawsuit should be dismissed because the 12-year statute of limitations to bring such a claim had expired. The federal statute of limitations starts to run in such property title disputes when a complainant knew or should have known that the United States claimed an interest in the land. Though the Army Corps has not deposited dredging spoils on the easement since 1992, the agency said it still holds a valid easement and that local government knew of the restriction on the site.
Oregon LNG sued the Army Corps over the issue last August. Oregon LNG has brushed off other adverse rulings against the project, which involves an 87-mile pipeline from Washington state through Columbia, Tillamook and Clatsop counties to a liquefied natural gas export terminal in Warrenton. Local, state and federal agencies are examining different aspects of the project. The Federal Energy Regulatory Commission has said the final environmental impact statement could be completed by next February.
China, India will need more LNG import terminals to handle supply
(Reuters; July 30) - What could go wrong for liquefied natural gas in Asia to derail the current consensus of strongly rising demand being met by supply that is increasing even faster? One of the assumptions that often remains unspoken when analyzing energy markets is the status of the infrastructure needed to ensure products can actually get from one place to another, and then be processed at their destination.
For LNG, there is little doubt about the wave of new supply coming in the next few years from Australia, the United States, Russia, Indonesia and Africa. The additions are already starting to overwhelm demand, causing prices to decline sharply. Spot-market Asian LNG fetched $8.10 per million Btu last week, down 20 percent since the start of the year and 60 percent from the record $20.50 in February 2014. Market consensus is that the growth in supply will outweigh the increase in demand over the next few years.
Looking longer term, LNG demand in Asia will grow by more than 40 percent, driven by China and India. But the question remains if China and India will be able to physically import the LNG that they are expected to need. Both will need to build a lot more LNG import terminals. It appears liquefaction capacity additions could overwhelm regas capacity worldwide. It seems unlikely — based on current plans — that enough regas capacity is being built to meet supply increases, particularly in China and India.
Sakhalin LNG plant could add third production train in 2021
(Reuters; July 30) - The third train at Russia's only LNG plant — Sakhalin-2, which opened in 2009 on the country’s Pacific coast — could be launched in 2021, Sakhalin Energy, which runs the project, said July 30. The venture is a partnership of Russia’s Gazprom, with Shell and Japan’s Mitsui and Mitsubishi as minority stakeholders.
Sakhalin Energy said in its corporate newspaper that the final investment decision on construction of a third train was expected in the second half of 2017. The third production train would allow an increase in capacity to 15 million metric tons of LNG per year (more than 700 billion cubic feet of natural gas), up from almost 10 million tons.
Low natural gas prices drive demand growth at U.S. industrial users
(LNG World News; July 30) - Reversing a decline that lasted more than a decade, U.S. industrial natural gas consumption has grown steadily since 2009 as relatively low natural gas prices have supported the use of natural gas as a feedstock for the production of bulk chemicals. Industrial facilities, including methanol plants and ammonia- or urea-based fertilizer plants, consumed an average of 21 billion cubic feet of gas per day in 2014, a 24 percent increase from 2009.
Several new industrial facilities began service this year, with additional projects scheduled to come online through 2018, the U.S. Energy Information Administration said in a recent report. The EIA forecasts that new projects will help drive growth in industrial natural gas demand through the end of 2016, climbing to 22.5 bcf a day. In 2016, three methanol plants are expected to come online in the Gulf of Mexico area, and a large nitrogen fertilizer plant is under construction on Louisiana’s Gulf Coast.
Ammonia- or urea-based fertilizer plants are also being planned in agricultural areas outside of the Gulf Coast region by developers hoping to take advantage of higher domestic gas production. Later this year, a large fertilizer/urea plant in Iowa is set to come online, and two fertilizer plants are planned for towns less than 75 miles away in southern Indiana. Each of the two plants would use 100 million cubic feet of gas a day.
Change in federal law will reduce tax on LNG as motor fuel
(Fleet & Fuels; July 30) – A provision in a federal highway funding bill “corrects a longstanding inequity,” NGVAmerica said July 30, “and will further expand the use of clean-burning domestic natural gas as a transportation fuel.” The president is expected to sign the bill into law “within the next day or two,” said the industry group Natural Gas Vehicles for America. The change would take effect Jan. 1, 2016. The change would assess federal motor fuel taxes on natural gas based on energy content, not volume.
Currently, the association said, fleets operating LNG-powered trucks are effectively taxed for their fuel at a rate 70 percent higher than that of diesel fuel. The new law modifies the highway excise tax on LNG to be based on energy content, rather than volume, and thus brings the tax on LNG into parity with that of diesel. “This fix reduces the excise tax on LNG from approximately 41.3 cents per diesel-gallon equivalent to 24.3 cents,” NGVAmerica said.
“Prior to the passage of the new law, the LNG truck would have a highway fuel tax bill of $8,262. With this change, the LNG truck will now pay $4,860 a year in highway fuel taxes, a savings of $3,402 per year,” the association said of a truck traveling 100,000 miles a year. A gallon of LNG provides less energy — fewer miles — than a gallon of diesel fuel. The trucking industry had been pushing for the federal tax to be based on energy, not volume, particularly with the growth of LNG as a fuel option.
AltaGas may build liquefied propane export plant on B.C. coast
(Calgary Herald; July 30) - AltaGas has advanced its plan to be the first to export liquefied propane from the B.C. coast, announcing July 30 it has struck an exclusive deal on an unspecified site and that it will build a new gas fractionating plant in northeastern B.C. to ensure supply. CEO David Cornhill said the Calgary-based company could invest more than $1 billion over the next two years in British Columbia, including the liquefied petroleum gas plant on the coast.
The investments could include a new fractionation facility worth about $100 million in the gas-producing region of Fort St. John in northeastern B.C., and a previously announced $350 million Townsend gas plant, also in northeastern B.C., along with associated pipelines. The propane export plant “will initially be able to handle 25,000 barrels per day with significant expansion opportunities,” Cornhill said. “We expect to finalize agreements by the end of the year.”
AltaGas said it will make a final investment decision next year. It is expected to boost propane prices by giving Canadian producers awash in the fuel an alternative to domestic or U.S. sales. The propane would be delivered to the coast by rail.
TransCanada says costs are rising for west-to-east oil pipeline
(The Canadian Press; July 31) - It’s looking like the Energy East project is going to get more expensive. TransCanada, which wants to build the controversial cross-Canada oil pipeline, had been estimating it would cost $12 billion. But the company warned July 31 the cost is expected to grow. On a quarterly conference call, CEO Russ Girling said the increase is due to adjusting the pipeline’s route following feedback from communities, governments and indigenous peoples as well as higher construction costs.
TransCanada did not provide an updated cost estimate. Energy East was already going to be one of the costliest infrastructure projects in Canadian history. For two-thirds of the way, TransCanada aims to convert an underused natural gas pipeline and then build all new pipe through Quebec and New Brunswick. According to TransCanada’s quarterly report, the company has already spent $700 million on Energy East — and regulatory hearings have not even started.
Alex Pourbaix, the company’s president of development, said considerable work and resources went into the hefty regulatory application filed last October. Ditto consultations with communities along the pipeline’s proposed 2,850-mile route through six provinces. TransCanada also had to do a significant amount of integrity work on the existing pipe to assure regulators it can be safely converted to ship oil, he added. The goal of Energy East is to feed Alberta crude to eastern refineries as well as exports.
TransCanada working with First Nations on Energy East oil pipeline
(Montreal Gazette; July 30) - TransCanada has quietly been meeting with First Nations leaders ahead of its Energy East pipeline project, signing 32 “capacity funding agreements” with aboriginal communities in the past two years. Through these agreements, the energy firm donates money to a reserve and, in return, gets to pitch its $12 billion project to community members. The 2,850-mile line would move Western Canadian oil sands production to the country’s East Coast for export and refineries.
TransCanada is heavily invested in these deals but insists none of its contributions to First Nations are meant to entice support for Energy East. Pending approval by the National Energy Board, construction is set to begin in 2020 and TransCanada said it simply wants to engage with aboriginal territories along the pipeline. The company has not disclosed the names of all of the First Nations it has talked with or signed deals.
In the latest deal, the company announced July 29 it signed an agreement with the Grand Council of Treaty 3 — which represents 24 First Nations in northern Ontario. Though the terms are confidential, some details were leaked to the Gazette. The agreement would see TransCanada fund a $700,000 environmental assessment of the project and its effects on Treaty 3 lands. There are confidentiality clauses, but Treaty 3 First Nations are free to oppose the pipeline and reject future deals with TransCanada.
Analyst predicts oil in the $30s by Christmas
(CNBC; July 30) - The prospect of oil prices falling below $40 receded earlier this year amid a crude rally, but with futures sliding again investors shouldn't rule out another drop, Again Capital founding partner John Kilduff said July 30. "Christmas time we'll probably be rebounding off new lows of the mid to low $30s," he told CNBC's “Squawk Box.” U.S. crude was trading around $49 July 30. "We have a lot to go. We're going to … trade down to the $30s in my view," Kilduff said.
A growing global glut of diesel fuel could be the next catalyst, he said, noting that Saudi Arabia and China have ramped up their refining capacity and are now flooding the Asian market with diesel. Recent developments in China and Iran may also contribute to another leg down in oil prices, Kilduff said. "I've been hearing a lot about how this Chinese stock market crash doesn't affect anything and doesn't count almost. For me, it's going to affect consumer confidence there," he said.
"If we see things like ... automobile sales coming down (in China), that hurts the outlook for oil demand growth and gasoline demand growth going forward." Meanwhile, China is beginning to buy up Iranian oil currently being stored in floating tankers, Kilduff said. Analysts believe Iran may have as much as 40 million barrels of oil sitting offshore. That crude could soon flood the market if world powers lift sanctions on the country following the deal over Iran's nuclear program.
Investors drawn to some smaller oil and gas companies
(Wall Street Journal; July 30) - Giant oil companies are weathering the oil-price slump better than the average shale driller, but even their famous stability is at times being surpassed by much smaller companies that own some of the choicest U.S. oil-and-gas fields. The stock price of Cimarex Energy, which drills in Texas and Oklahoma, has fared better than that of Chevron since crude-oil prices started crashing. Shares of Diamondback Energy, an 8-year-old oil producer with a $4.3 billion market value, have held up almost as well as ExxonMobil’s, while Cabot Oil & Gas has done better.
The better smaller companies tend to carry less debt than their peers and can coax fuel out of the ground at a lower cost. It is a combination that has proved at least as attractive as the deep pockets of the world’s biggest oil companies over the past year. Cimarex, Diamondback and Cabot have seen their shares fall between 20 percent and 30 percent. By contrast, an index of 21 U.S. energy companies, almost all of them oil-and-gas producers, has declined 52.3 percent over the same period.
“There have been a handful that have bucked the trend,” an analyst said of the best-performing shale drillers. That share-price buoyancy could be a sign that investors are betting on a rebound in oil and gas prices. Or it might be a bet that some of the smaller, most efficient players will be bought at a premium by the big oil companies, said Doug Terreson, head of energy research at Evercore. Another analyst said investors have flocked to drillers that operate with the greatest efficiency and promise to boost output.
Mozambique draws nine bidders on 30,000 square miles of acreage
(Reuters; July 30) - ExxonMobil, Italy's Eni and South Africa's Sasol are among the firms that submitted bids to explore new blocks in Mozambique and off its Indian Ocean coastline, a senior official said July 30. A total of 15 blocks in some 30,000 square miles were included in the fifth licensing round for which the Institute of National Petroleum closed bidding July 30. The successful bidders will be announced "within the next two to three months," institute chairman Arsênio Mabote said.
Nine companies submitted proposals for the blocks. The blocks on offer include three new areas of the northern Rovuma Basin, where Eni and Anadarko have found large gas reserves and are looking to develop multibillion-dollar liquefied natural gas export projects. The African nation is hoping that revenue from its gas deposits and fledgling coal mining industry will help it emerge from years of poverty and aid dependence.