Toshiba trying to unload billions of dollars in U.S. LNG
(Reuters; Feb. 17) - Japan's Toshiba, scrambling to fill the balance sheet hole left by a $6.3 billion hit to its nuclear operations, is also on the hook to pay billions of dollars for a U.S. liquefied natural gas contract. The conglomerate surprised many in 2013 when it unveiled plans to buy 2.2 million tonnes a year of the fuel from Freeport LNG in Texas, exposing it to more than $7 billion in charges over a 20-year period. The company still has no firm customer commitments for the gas, a Toshiba spokesman said Feb. 17.
Toshiba's contract requires it to either buy gas on the U.S. market to run through Freeport’s liquefaction plant and resell as LNG, or not buy any gas and pay a fixed fee to Freeport for the unused plant capacity of about $370 million per year for the life of the contract. The Toshiba spokesman said the company had an agreement with Japan's Jera, the world's biggest single buyer of LNG, to help market the fuel from 2019, when the Freeport contract goes into effect. The Texas plant is under construction.
Toshiba signed the deal at the height of Japan's energy crisis after the 2011 nuclear disaster led to shutdown of the country's power reactors, forcing Japan to spend huge sums on fuel imports. Many questioned why Toshiba was making a foray into the world of gas trading. "Signing up for gas is another example of Toshiba's poor management oversight," said Tom O'Sullivan, an energy consultant with years of experience in Japan. Toshiba's deal seemed like a good bet at the time as LNG prices surged to a record. Now, however, amid a global oversupply, they are half of what they were when Toshiba signed the deal. By 2015, Toshiba was trying to sell its LNG commitment.
Shell says new LNG customers look for shorter, smaller contracts
(Reuters; Feb. 20) - Shell, the world's biggest liquefied natural gas trader following its takeover of BG Group last year, said new LNG customers that will drive future demand are looking for shorter and smaller contracts. Shell expects much of new LNG demand to come from countries that want to replace declining domestic gas production — which has already happened in Egypt and Pakistan — and from those countries looking at LNG to complement pipeline and domestically produced gas, like China or Morocco.
Shell said it sold LNG into six new markets in 2016, compared with a typical two or three new national buyers a year. The new buyers typically need more flexibility in their gas supplies due to uncertainty over demand. It means the historical contract structure of large volumes sold in multi-decade deals is changing. "On average, term contracts are getting shorter and smaller, and that's in response to the introduction of new buyers to the market who have more uncertainty in their market positions," said Steve Hill, Shell's executive vice president for gas and energy marketing and trading.
New potential customers this year are Jamaica and Malta, which have built floating LNG receiving and storage units, as well as Ivory Coast, Hill said.
Tokyo Gas looks to expand its business outside Japan
(LNG Industry; Feb. 16) – Though Japan’s natural gas consumption hit record levels in January, the government forecasts that long-term demand for gas in the country will fall with a shift in the balance of energy consumption. Over the past two years, Japan has imported about 88 million metric tons of LNG per year, but government calculations show the volume is expected to fall to 60 million tons by 2030.
As a result, a growing number of Japanese energy businesses are diversifying in order to ensure their continued growth. Tokyo Gas plans to expand its global presence to help make up for lower sales at home. As one of Japan’s largest LNG buyers, the company has recently announced a number of international projects, including an exchange agreement that will enable it to reduce shipping times and costs on LNG cargoes and a possible venture serving commercial and industrial gas customers in Indonesia.
“Oil [demand] will peak by 2030, and demand for natural gas will increase in the next two decades because of new markets and new sources of energy,” said Shigeru Muraki, executive adviser to Tokyo Gas. “Governments will veer away from the installation of new coal-fired power stations as they will be very difficult to maintain both financially and politically, especially in light of the push to end global warming.”
LNG spot-market prices back down to $6.40 in Asia
(Reuters; Feb. 17) - Asian spot LNG prices fell for a sixth consecutive week as thin demand follows a warmer-than-expected winter in North Asia. Spot prices for liquefied natural gas for April delivery were pegged at around $6.40 per million Btu, about 50 cents below last week's levels, according to five traders surveyed by Reuters.
"LNG prices are collapsing lately, because winter is mostly done," a Singapore-based trading source said. Falling prices at Britain's gas trading hub have dashed expectations of an influx of shipments heading to Europe. The bearish sentiment in Asia has been compounded by the "shoulder season" — a period of low LNG demand — after winter.
Total continues with strategy to invest in downstream gas demand
(Platts; Feb. 15) - France's Total is looking to invest in energy projects further downstream than their upstream and liquefied natural gas production facilities, the company’s president of gas Laurent Vivier said Feb. 14. The demand-build strategy is a logical change given the currently tough environment for final investment decisions for new greenfield LNG production projects, Vivier said.
What some industry observers are underestimating is the pace that new buyers can enter the market, Vivier said. Total has interests in two recently announced LNG import projects in the Ivory Coast and Pakistan that could take a combined 9 million metric tons per year and start receiving LNG in 2018. Both projects would allow for quick entrance into the market, utilizing floating receiving, storage and regasification units. "We are now ready to invest downstream in the value chain," Vivier said.
The key to helping absorb much of the world’s oversupply of LNG is new demand coming from unexpected areas that were not forecast to require gas three years ago, Vivier said. Over the next three years, he expects to see more LNG importers in growing economies rapidly gain access to the market.
Indian state withdraws tax break on LNG imports
(Bloomberg; Feb. 16) - A province governed by India’s Prime Minister Narendra Modi for 13 years is impeding his plans to promote clean energy. Modi’s effort to make liquefied natural gas more affordable by halving its import tax in the federal government’s 2017 budget is being scuttled by withdrawal of tax benefits by the western Indian state of Gujarat, through which 90 percent of the LNG used in India passes.
Loss of the state concession has resulted in higher prices for domestic and industrial consumers across India. It has also sparked criticism from environmental groups that fear it will hurt the competitiveness of gas and discourage use of the cleaner fuel. India is struggling to follow the U.S. and Europe in giving gas a greater role in its energy basket as it battles air pollution. Levies across the country add about 40 percent to the delivered price of LNG by the time it reaches the end user, said Prabhat Singh, CEO of Petronet LNG, the nation’s biggest importer of the fuel.
Gujarat, which houses the nation’s biggest LNG import terminals, withdrew the tax waiver on imported fuel consumed outside the province in November. The withdrawal of the tax credit has resulted in an effective value-added tax rate of 15 percent, up from 4 percent earlier, said Rajeev Kumar Mathur, managing director of Mahanagar Gas. “If gas needs a push, we need to soften the taxes,” said B.C. Tripathi, chairman of India’s biggest gas utility, GAIL India. Currently, import taxes are levied on LNG but not crude oil, he said. That along with other levies makes gas uncompetitive.
LNG exports partly blamed for higher gas prices in Australia
(Australian Broadcasting Corp.; Feb. 16) – East Coast Australia's domestic natural gas shortage is crippling some rural businesses, and has prompted one owner to accuse the nation's politicians of treason. Chris Cummins, from Cowra in regional New South Wales, owns a slaughterhouse and is about to lock in a two-year contract with his gas supplier. He expects the price to surge by about 60 percent. "We are going to be $100,000 a month worse off in costs for our gas," Cummins said.
He wants the federal government to find some answers. It comes amid a furious debate in parliament about large hikes in gas bills. Australian Competition and Consumer Commission Chairman Rod Sims said the East Coast gas shortage is not getting the attention it deserves. "We are not only short of gas. We also — particularly in New South Wales and Victoria — do not have enough gas suppliers," he said. The consumer commission points to several factors driving the gas shortage, including exports.
A lot of the East Coast’s gas is leaving the country, largely committed under long-term contracts. Most of Australia's liquefied natural gas is exported to Asia; the domestic market has to compete for gas. "We then had the almost unanticipated bans or difficulties with developing gas deposits in New South Wales and Victoria," Sims said. Four Australian states and territories have banned fracking, and the federal government is urging them to lift the moratoriums. Sims said more gas exploration is critical.
Russia considering tax break for older oil fields
(Bloomberg; Feb. 14) - Russia’s largest oil field, so far past its prime that it now pumps almost 20 times more water than crude, could be on the verge of gushing profits again for Rosneft. Samotlor, the 25-billion-barrel field that bankrolled the Soviet Union for decades, would be the biggest beneficiary of tax-break proposals to encourage investment in some of Russia’s oldest and largest reservoirs, where output is plunging.
One idea being debated — cutting the extraction tax in half for fields producing a lot of water with the oil — could add as much as $1.6 billion a year to Rosneft’s earnings, said Alexander Kornilov, an analyst at Aton in Moscow. “It is a super-giant field even today after almost 50 years of production, the elephant of elephant fields,” said Ildar Davletshin, an analyst at Renaissance Capital. But production is costly because it takes 95 barrels of water to get 5 barrels of crude out of the ground, he said.
Russian ministries are still considering the viability of the proposal to reduce the tax on eligible fields if the oil they produce has a water content of more than 90 percent, according to a government official. Right now, all the fields that meet these criteria belong to Rosneft, said another person. Samotlor’s output fell 4.7 percent in 2015 to about 425,000 barrels a day, according to Rosneft’s website. It declined by another 4.1 percent over the first nine months of 2016 compared to a year ago.
Some analysts worry oil industry may be celebrating too soon
(EnergyWire; Feb. 17) - The hats with the words "Make Oil and Gas Investing Great Again" epitomized the mood at the first major oil and gas gathering of the year in Houston. Though just a few months have passed since the oil bust was semi-officially declared over, industry is already raring to go. Steady oil prices north of $50 per barrel and confidence in the promises of OPEC are driving industry to grab acreage, cut deals and get to drilling again. Attendance is up at the North American Prospects Expo 2017, which draws thousands from around the world to prospect for new drilling opportunities.
But some analysts are beginning to think the frenzy is getting a little ahead of itself. With Wall Street betting long on the return of $60-per-barrel oil, there may be risk of prices sliding back into the $40 range or lower, judging by the frenetic pace to drill again in the U.S. Some 200 rigs have returned to active drilling in less than a year, most within the past six months. Payrolls are up and companies are talking about boosting spending.
The industry is optimistic by nature, but Sarp Ozkan, an analyst with Drillinginfo, argues it may be moving too quickly. Yes, OPEC held to most of its promised production cuts in January, but it needs to maintain its restraint for the full year, he said, while in the past cheating on quotas has been the norm, not the exception. Meanwhile, Drillinginfo and others harbor suspicions that oil demand will not expand this year as much as OPEC or the International Energy Agency are predicting. If stronger demand growth forecasts don't pan out, experts say we're likely to see choppy waters for quite some time.
Oil sands reserves could be stranded by high costs, low prices
(Wall Street Journal; Feb. 17) - A new era of low oil prices and stricter climate-change regulations is pushing energy companies and resource-rich governments to confront the possibility that some fossil-fuel resources will remain in the ground indefinitely. In a signal that the prospect is growing more likely, ExxonMobil has said that as many as 3.6 billion barrels of oil that it planned to produce in Canada in the next few decades is no longer profitable to extract. A disclosure is expected in the coming week.
The company said it still expects the oil will be developed and added back to its reserves if prices rise, costs fall or its operations improve. Exxon’s acknowledgment — after the company spent about $20 billion to put the oil sands at the center of its growth plans — highlights how dramatically the prospects of the region have dimmed. Once considered a safe bet, Canada’s vast deposits are emerging as a prominent case of reserves stranded by a combination of high costs, low prices and environmental rules.
Such projects can require billions of dollars in upfront investment and seven to 10 years, or even more, to bring returns. Now companies are turning to new sources, such as shale, that don’t require the same investment of time and money to bring to production. Canada was once thought to hold the world’s third-largest trove of crude, largely due to the oil sands in Alberta — giant deposits of crude with the consistency of a hockey puck. Today, only about 20 percent of those reserves, or about 36.5 billion barrels, are capable of being profitable, according to energy consultancy Wood Mackenzie.
Pennsylvania puts limits on Hilcorp’s fracking operations
(Pittsburgh Post-Gazette; Feb. 18) - State regulators have placed conditions and monitoring requirements on Hilcorp Energy’s fracking operations in western Lawrence County, Pa., to reduce the risk that its deep gas well activities could trigger more small earthquakes like the ones the company is suspected of causing last April. The state Department of Environmental Protection concluded that fracking in two of the wells showed a “marked” link in space and time to a series of minor tremors on April 25.
The requirements so far apply only to Hilcorp’s operations in three townships, but state officials said they will write a regulation to apply to all companies in areas where Utica Shale operations might be susceptible to seismic risks because of proximity to faults or brittle basement rock. The Lawrence County earthquakes are the first known incidents of fracking-linked quakes in Pennsylvania. Researchers have linked fracking to quakes in Ohio, Oklahoma, Canada and the U.K., but science on induced quakes is evolving.
Hilcorp was fracking two of four Utica wells using “zipper fracking,” in which two parallel wellbores spaced close together are injected with high-pressure fluids simultaneously to extract more gas from the shale, according to the state report. The tremors registered 1.8 to 2.3 on the Richter scale. Hilcorp voluntarily stopped its activities at the well pad on April 25 and discontinued fracking operations at the site indefinitely. The state’s new rules call for Hilcorp to continue operating its own seismic monitoring network in the area and to stop using zipper fracking on wells closer than a quarter-mile apart.
Proposed Canadian mine will consider trucked LNG for power
(Press release; Feb. 14) - Canadian Zinc Corp. has signed a memorandum of understanding with Northwest Territories Power Corp. to look at how to supply electrical power for development and operation of the proposed Prairie Creek Mine in Canada’s Northwest Territories, about 100 miles north of the British Columbia border. The mining company and power provider also agreed to evaluate the use of liquefied natural gas trucked to the region to generate electricity for the mine.
The power company also is studying the potential to use LNG for electrical generation in local communities to cut dependence on diesel. The Prairie Creek mine is undergoing a “definitive feasibility study,” the mining company said. Over the 17-year life of the mine, Prairie Creek's annual production is projected to average about 60,000 tonnes of zinc concentrate and 55,000 tonnes of lead concentrate, with 1.7 million ounces of silver.
TransCanada tries again for Keystone route approval in Nebraska
(The Canadian Press; Feb. 16) - TransCanada is once again seeking approval of its Keystone XL pipeline route in Nebraska in its latest move to push the polarizing project forward since getting a nod from U.S. President Donald Trump. The company said it expects a decision from the Nebraska Public Service Commission by the end of the year. But opponents are looking to the commission’s public hearing process to halt or reroute the oil sands line over concerns a spill could contaminate the Ogallala Aquifer.
“We’re an ag state, not an oil state, and so we don’t think that we should be risking our water supplies and the agricultural economy so Canada can get their tar sands to the export market,” said Jane Kleeb, president of the Bold Alliance group that is pushing against the project. Kleeb said she is confident that opponents will be successful through the Public Service Commission process, which TransCanada has turned to after first trying to use eminent domain to seize privately owned land for the pipeline.
The commission will have to determine if the pipeline carrying some 830,000 barrels a day of Alberta crude toward the Gulf Coast will serve the public interest. TransCanada said more than 90 percent of landowners in Nebraska have signed easements for the project, while Kleeb said there are 82 landowners who oppose the route and have refused. The company filed a presidential permit application for the project after being invited by President Trump, who has asked that the federal review proceed quickly.