Natural Gas Is Flaring Up

Rising Natural Gas Prices Are a Hot Bet…

Investors, who just weeks ago shunned the fuel and the companies that sell it, are unwinding wagers that prices will fall, bidding up producers’ beaten-down shares and even buying their new bonds.

The reason for optimism: The historic collapse in crude prices thanks to the new coronavirus has energy producers racing to close oil wells.

Shutting in productive wells in crude-drilling regions like North Dakota and West Texas not only keeps oil in the ground and off the flooded market, it also chokes off a lot of gas that is extracted as a byproduct. When crude prices last month dipped below $0, natural gas prices had their best day in more than a year, popping 9.75% on the prospect that many money-losing wells will be capped.


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Meanwhile, coal, not gas, has suffered the worst of the reduced demand for electricity during the pandemic. Coal’s share of U.S. electricity generation is down by about a third from last year, according to Energy Information Administration data.

The result is renewed interest from investors in natural gas and its producers.

Hedge funds and other speculators on April 21 became net long—with more wagers on rising gas prices than bets counting on decline—for the first time since last May, according to Commodity Futures Trading Commission data.

They added bullish positions this week. Though the difference between long and short bets is relatively small, it represents a dramatic shift in sentiment. Gas speculators were piled into their largest net short position on record in mid-February.



Since February, shares of Appalachian gas producers EQT Corp. and Range Resources Corp. have more than doubled while CNX Resources Corp. stock has gained 91%. The broader stock market has been down 4.2% over that same time, and the sector’s benchmark SPDR S&P Oil & Gas Exploration & Production exchange-traded fund has lost 19%. Over the past three months, Cabot Oil & Gas Corp., a top producer in Pennsylvania, has risen 45%, second best in the S&P 500 after Regeneron Pharmaceuticals Inc., which investors have banked on developing a Covid-19 treatment.

SunTrust Robinson Humphrey analysts raised price targets for shares of seven gas producers by an average of 69%. Tudor, Pickering, Holt & Co. recommended shares of EQT, Cabot Oil & Gas Corp. and Tourmaline Oil Corp. in Canada to capture near-term gains related to what the Houston firm estimates will be 6 billion to 7 billion cubic feet of gas a day leaving the market as oil wells are shut.

Debt investors are warming too. EQT’s bonds traded down to 61 cents on the dollar in March but are back up to near par. Last week, the Pittsburgh company launched a $350 million convertible bond offering that generated so much interest that it ended up issuing $440 million of debt, according to CreditSights, which upgraded its rating of EQT. CNX followed with its own offering this week of $300 million of debt that can be swapped for shares.

Natural gas futures for June delivery lost 3% on Friday to close at $1.89 per million British thermal units after climbing to $2.016 in early trading. That’s still too low for many gas wells to be profitable, yet the price is up 22% from the 25-year-low of $1.552 on April 2 and the trend is higher heading into summer, when there’s demand to power air conditioners, and more so in winter, when a lot of gas is burned for heat.

Futures for July delivery reached $2.25 Friday before giving up gains. December gas nosed briefly above $3.

“We think the dry gas producers are attractive,” said Mark Unferth, a portfolio manager at Alpine Capital Research, referring to companies that don’t produce much poorly priced oil and natural gas liquids. “We’ve been adding to our exposure the past six weeks and overall it’s about 5% of our portfolio.”

Companies like EQT and CNX, which make their money selling gas, had to rapidly lower operating costs to keep up with oil-drilling competitors that didn’t particularly care about the price of gas and flooded the market with it when crude prices were higher. As U.S. oil production surged to records, so did gas output. Appalachian gas producers had to adapt to prices first below $3 and then this past winter to less than $2.


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Those efficiency gains should translate to profits on even small improvements in gas prices, Mr. Unferth said.

“When gas prices were at $3.50 you could afford to be sloppy but low prices have forced people to be a lot more efficient in the field,” he said.




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A Glut Of Cheap Natural Gas Is Wreaking Havoc On The Energy Industry

A decade ago, natural gas was heralded as the fuel of the future. In shale fields across the country, hydraulic fracturing uncorked a lucrative new source of supply. Energy giants like Exxon Mobil and Chevron snapped up smaller companies to get in on the action, and investors poured billions of dollars into export terminals to ship gas to China and Europe.

The boom has given way to a bust. A glut of cheap natural gas is wreaking havoc on the energy industry, and companies are shutting down drilling rigs, filing for bankruptcy protection and slashing the value of shale fields they had acquired in recent years.




The New Geopolitics of Natural Gas

We are in the midst of an energy revolution, led by the United States. As the world’s greatest producer of natural gas moves aggressively to expand its exports of liquefied natural gas (LNG), America stands poised to become an energy superpower―an unanticipated development with far-reaching implications for the international order. Agnia Grigas drills deep into today’s gas markets to uncover the forces and trends transforming the geopolitics of gas.




Chevron, the country’s second-largest oil and gas giant after Exxon, said on Tuesday that it would write down $10 billion to $11 billion in assets, mostly shale gas holdings in Appalachia and a planned liquefied natural gas export facility in Canada. The move was an energy company’s clearest acknowledgment yet that the industry has been far too optimistic about the prospects for natural gas.

While cheap natural gas continues to take market share from coal in the electricity sector, supply of the fuel has far outstripped demand. As a result, once-booming gas fields in Arkansas, Louisiana and Texas have become quiet backwaters. The number of gas rigs deployed nationwide has dropped to 132, from 184 last year.

“In the short term the gas market is oversupplied and is likely to remain so for the next few years,” said Andy Brogan, oil and gas global sector leader at EY, the firm formerly known as Ernst & Young. “It’s a cyclical business, and we’re at the bottom of the cycle.”

Some analysts said the gas slump could persist for some time because the cost of wind and solar energy has tumbled in recent years, making those renewable sources of energy more attractive to power producers. And while gas exports are climbing, growing production of the fuel in Qatar, Russia and Australia threatens to drive down international prices over the next few years.







Nowhere are the declining fortunes of natural gas more in evidence than in Appalachia, where the Marcellus field centered in central and western Pennsylvania was once viewed as the most promising in North America. With gas prices slashed nearly in half from a year ago, the number of drilling rigs operating in Pennsylvania has dropped to 24, from 47, over the last 12 months. EQT, one of the premier producers in the Marcellus, recently cut nearly a quarter of its work force, eliminating 196 positions.

That is a far cry from the picture Chevron painted when it acquired Atlas Energy almost exactly 10 years ago for $3.2 billion, while assuming $1.1 billion in debt, cementing its foothold in southwestern Pennsylvania. At the time, George L. Kirkland, then Chevron’s vice chairman, predicted that the “strong growth potential of the asset base and its proximity to premier natural gas markets make this targeted acquisition a compelling investment.”

Other energy companies have also acknowledged losses, though not to the same extent. Exxon Mobil wrote down the value of its American natural gas assets by $2.5 billion in recent years after buying the natural gas producer XTO Energy for more than $30 billion in 2010.

Gas producers have struggled in part because New York and other Northeastern states have made it harder to build pipelines to transport the fuel. But analysts point to a far bigger problem: The industry is just producing too much gas. In some oil fields where gas bubbles to the surface with crude, it has become cheaper for producers to burn the gas than gather it and send it to market.

“Natural gas is in the tank,” said Patrick Montalban, president of Montalban Oil & Gas Operations. “We’re looking at a project right now of over 200 wells in Montana that are for sale, but they are uneconomic. Not only are the wells uneconomic, the gathering of the gas is uneconomic.”

American natural gas inventories are about 19 percent higher than a year ago, according to the Energy Department. The government estimates that the average spot price for natural gas will be $2.45 per million British thermal units in 2020, about 14 cents below this year’s average. At its peak in 2008, the benchmark price topped $10 per million British thermal units.

Exports of liquefied natural gas are rising sharply, but future profits may be meager. S&P Global Platts warned this week that European gas prices could slide next year, reducing how much money United States exporters can earn.

Moody’s Investor Service predicted that several gas exploration and production companies active in the Marcellus will face heightened financial risks over the next three years because of the debt they have accumulated. Between 2021 and 2023, companies such as Antero Resources, CNX Resources, EQT and Gulfport Energy will need to refinance between $3.5 billion and $4 billion in debt. All told, the producers have to repay lenders more than $12 billion during that period.

“If low natural gas prices persist beyond 2020,” the Moody’s report said, “companies may need to reduce debt to maintain compliance with financial covenants or amend covenant levels.”

Many smaller companies have sought bankruptcy protection or indicated that they could go out of business. Shares of Chesapeake Energy, the Oklahoma-based champion of shale gas drilling, traded at more than $60 in 2008. Now they sell for less than a dollar. Chesapeake warned in a recent securities filing that if prices remained low and it was unable to comply with the conditions of its debt, “there is substantial doubt about our ability to continue as a going concern.”

Such pessimism is widespread… “We expect the trend of write-downs to continue as price outlooks are adjusted down,” said Tom Ellacott, senior vice president at Wood Mackenzie, a research firm.

Of course, low natural gas prices have been a boon to users of the fuel, especially electricity utilities, which are increasingly replacing coal-fired plants with ones that use gas. Gas is expected to have provided about 37 percent of electricity produced in the United States this year, up from 34 percent in 2018, according to the Energy Department. But renewables are climbing even faster.

In a recent report, Morgan Stanley estimated that demand for natural gas would grow for a few years but fall 13 percent between 2020 and 2030 as utilities increasingly switch to wind and solar power. Future regulations or a carbon tax put in place by lawmakers worried about climate change could accelerate the transition to renewables.

Exports offer perhaps the greatest growth potential for American natural gas. But even as companies build more liquefied natural gas export terminals across the Gulf Coast, competition from Russia and Qatar is intensifying and analysts fear there could soon be a global glut of gas.

“There is significant uncertainty as to the scale and durability of demand for imported L.N.G. in developing markets around the world,” the International Energy Agency said in a recent report. Considering the high cost of processing and transporting liquefied natural gas, the report added, “competition from other fuels and technologies, whether in the form of coal or renewables, loom large.”



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Natural-Gas: Prices in Europe and Asia Plummet to Historic Lows

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♦ Natural Gas – Stock Market News ♦ … — Natural-gas prices in Europe and Asia have plummeted this year to historic lows in the midst of reduced demand, the trade dispute with China and brimming storage facilities in Europe. The biggest driver of falling prices, though, has been the U.S. Natural Gas that is spilling into global markets.

“It was inevitable,” said Ira Joseph, head of global gas and power analytics at S&P Global Platts. “There is simply too much supply coming into the market at one time.”



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The price decline has eliminated some of the allure involved in liquefying cheap U.S. gas and shipping it abroad, where it typically fetches much higher prices.

That is a concern for the exploration-and-production companies that have flooded the market with cheap shale gas and are already struggling with flagging shares and restive shareholders.


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The more international prices fall, the better the chance that the waterfront facilities that produce liquefied natural gas, or LNG, for overseas shipment will reduce their intake of gas, which has helped keep domestic gas prices from collapsing completely this year.

U.S. natural-gas futures for September delivery settled Tuesday at $2.202 per million British thermal units. That is down about 25% from this time last year despite the surge in exports and record consumption among U.S. power plants this summer to generate electricity in response to sweltering heat.


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The benchmark price for natural gas in Asia, the Japan Korea Marker, has fallen to as low as $4.11 per MMBtu this summer, down from more than $11 per MMBtu a year ago, according to S&P Global Platts. Meanwhile, a widely used European price set in the Netherlands has dropped to nearly $3, from about $9 a year ago.

Those prices don’t leave much margin for U.S. sellers. Though processing and shipping costs can vary by exporter and destination, $2 per million BTUs is typical, analysts say. Houston’s Tudor, Pickering, Holt & Co. estimates that about 25% of the global LNG market is subject to spot prices, as opposed to pricing that is sketched out in long-term supply contracts.

The squeeze comes in the midst of the biggest expansion yet of LNG shipping capacity.

Earlier this month Freeport LNG Development LP’s export terminal in a beach town south of Houston began buying and liquefying gas with the expectation of sending out its maiden cargo in September. The Freeport facility, the fifth to begin operating in the lower 48 states since the first opened in early 2016, should help push gas consumption from LNG exporters to a new high. Last week, a record nine LNG vessels left the U.S. carrying cargoes, according to Jefferies Financial Group Inc.

In July, LNG exporters consumed an average of about 6 billion cubic feet of gas per day, according to the U.S. Energy Information Administration. That is the most yet and is equal to roughly 7% of total U.S. gas production. Analysts expect demand from LNG facilities to absorb about 12% of total production by next summer as additional facilities start up and existing terminals boost their capacity.


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But if those projects are delayed because of low prices overseas or if existing LNG plants slow down or take advantage of the lull to perform extended maintenance, then the domestic gas market could be swamped, sending prices even lower.

“If that demand goes away even for a couple months, it becomes a real problem for the balance of the market,” said Welles Fitzpatrick, an analyst with SunTrust Robinson Humphrey.

The reliance of U.S. producers on demand around the world is a stark change from just a few years ago, when domestic gas prices were isolated from global markets and depended mostly on weather-related demand.

These days, though, U.S. gas prices take into account a range of overseas factors, such as Japan’s nuclear-reactor output, trade negotiations with Beijing and Dutch stockpiles.

The EIA, for instance, has estimated that Japan’s imports of LNG will decline by as much as 10% this year as nuclear reactors that were shut down after 2011’s Fukushima accident return to service.

At the same time, shipments to China essentially ended after the country placed a 10% tariff on U.S. LNG last September and boosted the levy to 25% in June in its tit-for-tat trade dispute with President Trump. Meanwhile, EIA data shows an increase in shipments to European countries, including the Netherlands and Spain, where gas is stored for later use.


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Many of those facilities are reaching capacity, however, and some analysts have expressed concern that buyers in those European markets may become sated until inventories are drawn down to heat homes this winter.




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The U.S. Is Overflowing With Natural Gas But The Infrastructure Needed To Move Gas Around The Country Hasn’t Kept Up


America is awash in natural gas…. Earlier this year, two utilities that service the New York City area stopped accepting new natural-gas customers in two boroughs and several suburbs. Citing jammed supply lines running into the city on the coldest winter days, they said they couldn’t guarantee they’d be able to deliver gas to additional furnaces. Never mind that the country’s most prolific gas field, the Marcellus Shale, is only a three-hour drive away.


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Meanwhile, in West Texas, drillers have so much excess natural gas they are simply burning it off, roughly enough each day to fuel every home in the state.

U.S. gas production rose to a record of more than 37 trillion cubic feet last year, up 44% from a decade earlier. Yet the infrastructure needed to move gas around the country hasn’t kept up. Pipelines aren’t in the right places, and when they are, they’re usually decades old and often too small.



The result, despite natural-gas prices that look low on commodities exchanges, is energy feast and famine.

This spring, the price of natural gas at a trading hub near Midland, Texas, dropped as low as negative $9 per million British thermal units—meaning that producers were paying people to take it off their hands. (A million British thermal units is enough to dry about 50 loads of laundry.)

Elsewhere, prices soared due to bouts of cold weather coupled with supply disruptions, including an explosion along a British Columbian pipeline and a leaky underground storage facility near Los Angeles. At a trading hub in Sumas, Wash., natural gas rose to $200 per million British thermal units in March, the highest ever recorded in the U.S. In Southern California, prices went as high as $23; the average over the winter was a record $7.23.

The national benchmark, which is set at a knot of pipelines in Louisiana, recently hit a three-year low of $2.19 and has hovered below $3 for much of the year.

“I don’t recall a situation when we’ve had the highs and lows happen in such extremes and in such relatively close proximity,” says Rusty Braziel, a former gas trader who now advises energy producers, industrial gas buyers and pipeline investors.


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With U.S. homes, power plants and factories using more natural gas than ever, the uneven distribution of the shale boom’s bounty means that consumers can end up paying more or even become starved for fuel, while companies that can’t get it to market lose out on profits. Around New York City, the dearth of gas has cast uncertainty over new developments and raised fears of stifling economic growth.

One reason for the problem is that pipelines have become political. Proponents of reducing the use of fossil fuels have had little luck limiting drilling in energy-rich regions. Instead, they’ve turned to fighting pipeline projects on environmental grounds in regions like New York and the Pacific Northwest, where they have a more sympathetic ear.

Even in Texas, the heart of the oil-and-gas industry, new pipelines have started to meet more local resistance. In April, landowners, Hays County and Kyle, a booming city on the outskirts of Austin, sued to block construction of a 430-mile pipeline that would move gas from the West Texas drilling fields, where it is being burned up, to buyers near Houston. The case was dismissed by a Texas judge in June.

Before pipelines… Natural gas, which is often found alongside oil and coal, was once a nuisance to drillers and miners alike. It would send crude shooting up out of wells like flammable geysers and was at risk of exploding in mineshafts. Before the advent of arc-welded pipelines that could be laid over long distances, gas had little value unless it happened to be very close to early industrial cities, like Pittsburgh or Cleveland.

After World War II, energy producers repurposed oil pipelines to ship gas to fuel the hungry furnaces and factories of the Northeast. By the beginning of the 21st century, many thought the U.S. was running out of gas. The national price averaged about $6 over most of that decade and at times rose to more than $12. Pipelines were built to move imported gas from the country’s borders, particularly along the Gulf Coast, into the interior.

Then the fracking revolution arrived, flooding domestic gas markets and rendering a lot of supply routes irrelevant. Within a generation, the U.S. has gone from importing gas to becoming a leading exporter.

These days, it’s a hassle getting gas from drilling fields like the Marcellus and Utica shales in Appalachia, and the Permian Basin in West Texas, to customers in northern cities. Many pipelines now run the other way: to move gas toward the Gulf Coast, where exporters can usually buy it for less than $3 per million British thermal units, and ship it overseas as liquefied natural gas, or LNG, for higher prices.


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A 99-year-old law prevents foreign tankers from shipping gas within the U.S. There are no domestic LNG tankers, mostly because the hundred-million-dollar-plus ships are much less expensive to build in Asia. So consumers in New England relied on importing liquefied natural gas from Trinidad and Tobago and even Russia to keep prices in check this past winter.

n New York, commercial real-estate broker John Barrett said he was completing the sale of a development that would become a 66-unit apartment building, when Consolidated Edison Inc. announced it would no longer take on new gas customers after March 15 in the southern part of Westchester County. The developer canceled the deal signing and backed out of the purchase two weeks later.

The future of a nine-figure development in New Rochelle, which would include a new city hall, fire station and affordable housing units, is suddenly in doubt. In Yonkers, Mayor Mike Spano worries that the gas moratorium will foul up plans for a mixed-use development on a big downtown parking lot.

Homes that don’t come with natural gas lines are now a tougher sell, said Mark Nadler, director of Westchester sales at Berkshire Hathaway Homeservices, unless buyers don’t mind cooking on an electric range or refilling tanks of heating oil each autumn.

Con Edison is trying to adapt to a world without additional pipelines. Scott Butler, from the company’s “utility of the future” department, said the team has explored trucking in emergency fuel supplies and even making its own fuel. The utility has proposed building three new facilities in the New York City area to turn compost and food scraps into gas. It is also planning to haul in natural gas on trucks, as many as 180 of them on the coldest days.


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Natural gas has long been considered a transition fuel—a placeholder that’s cleaner-burning than coal or oil but more dependable than renewables like wind or solar. But natural gas still releases carbon dioxide into the atmosphere, and fracking has its own environmental consequences, including the production of toxic wastewater. That has raised resistance to building new pipelines as well as enlarging old

Shale Companies, Adding Ever More Wells… Newer Wells Drilled Close To Older Wells Are Generally Pumping Less Oil And Gas And Could Hurt Output


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Shale companies’ strategy to supercharge oil and gas production by drilling thousands of new wells more closely together is turning out to be a bust. What’s more, the approach is hurting the performance of older existing wells, threatening the U.S. oil boom and forcing the maturing industry to rethink its future.

To maintain America’s status as an energy powerhouse, shale companies in recent years have touted bunching wells in close proximity, greatly increasing the number of wells drawing on a promising reservoir. The added wells would produce as much as older ones, many drillers believed, allowing them to extract more oil overall while maintaining strong returns from each well.



Those rosy forecasts helped fuel investor interest in shale companies, which raised nearly $57 billion from equity and debt financing in 2016, according to Dealogic, even as oil prices dipped below $30 a barrel. That was up from nearly $34 billion five years earlier, when oil topped $110 a barrel.

Now the results are coming in, and they are disappointing. Newer shale wells drilled close to older wells are generally pumping less oil and gas than the older wells, according to early corporate results. Engineers warn the new wells could produce as much as 50% less in some circumstances.


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The newer shale wells often interfere with the output of older wells, because blasting too many holes in dense rock formations can damage nearby wells and lower the overall pressure, making it harder for oil to seep out. The moves could potentially cause permanent damage and lower the overall amount recovered from a reservoir.

Known in the industry as the “parent-child” well problem, the issue is surfacing in shale hot spots across the U.S. as companies ramp up production. Most of the tens of thousands of planned new wells will be child wells—wells drilled close to an already producing well.

It is one of the primary reasons why thousands of shale wells drilled in the past five years are producing less oil and gas than companies forecast to investors, a Wall Street Journal examination of drilling data has found.

In February 2018, RSP lowered its estimate of drilling spots in the area to 2,440 wells. The company said it had found that spacing wells closer than 400 feet hurt production, and it had come to believe that 450 feet was the optimum spacing in the Midland area.


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A month later, in March 2018, Concho Resources acquired RSP for $9.5 billion, or about $75,000 per acre, creating a Permian giant. In a presentation announcing the deal to investors, Concho estimated RSP’s total inventory of drilling sites, which includes areas outside Midland, was about 30% lower than RSP’s previous estimate.

A Concho spokeswoman declined to comment. The company has previously said it would drill wells 660 feet apart in the Midland area and that synergies created by the merger will save money and allow it to go into a “manufacturing mode” of large-scale drilling projects.

When the deal closed in July, the combined market cap of Concho and RSP was nearly $30 billion. The current value of the combined company is $22 billion.


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U.S. homes and businesses used record amounts of natural gas for heating during the brutal freeze blanketing the eastern half of the country on Wednesday


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U.S. Homes and Businesses Used Record Amounts of Natural Gas for Heating


By Scott DiSavino | Reuters

Several utilities urged customers to cut back on power and gas use on Thursday during the brutal freeze blanketing the eastern half of the country after U.S. homes and businesses used record amounts of natural gas for heating on Wednesday.

Harsh winds brought record-low temperatures across much of the Midwest, causing at least a dozen deaths and forcing residents who pride themselves on their winter hardiness to huddle indoors.

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As consumers cranked up heaters to escape the bitter cold, gas demand in the Lower 48 U.S. states jumped to a preliminary record high of 145.1 billion cubic feet per day on Wednesday, according to financial data provider Refinitiv.

That topped the current all-time high of 144.6 bcfd set on Jan. 1, 2018. One billion cubic feet is enough gas to supply about five million U.S. homes for a day. In Michigan, auto makers agreed to interrupt production schedules through Friday after local utility Consumers Energy made an emergency appeal to curtail gas use so it could manage supplies following a fire at a gas compressor station on Wednesday.

Fiat Chrysler Automobiles NV said on Thursday it canceled two additional shifts at its Warren Truck and Sterling Heights Assembly plants and General Motors Co said it was suspending operations at a total of 13 Michigan plants and its Warren Tech Center. Ford Motor Co said it had also taken steps to reduce energy use at its four Michigan plants supplied by CMS.


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Consumers, a unit of Michigan energy company CMS Energy Corp, said that the Ray compressor station in Macomb County was partially back in service but urged all of its 1.8 million Michigan customers to continue their conservation efforts through Friday. Elsewhere in Michigan, DTE Energy Inc asked its 2.2 million power customers to reduce electric use voluntarily to help safeguard the reliability of the regional grid.

PJM, the electric grid operator for all or parts of 13 states from New Jersey to Illinois, said there were no reliability issues and noted that power demand had already peaked on Thursday below 140,000 megawatts. That is well below the PJM region’s all-time winter peak of 143,338 MW set on Feb. 20, 2015. One megawatt can power about 1,000 homes.

While the brutal cold boosts gas use for heating, it can also reduce production by freezing pipes in gathering systems in producing regions, called freeze-offs.


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Gas production in the Lower 48 states was projected to fall to a four-month low of 84.9 bcfd on Thursday due primarily to freeze-offs in the Marcellus and Utica, the nation’s biggest shale gas-producing region in Pennsylvania, Ohio and West Virginia, according to Refinitiv.

Europe is fast-becoming a natural gas battleground for Russia and the US


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With 28 countries and a combined population of around 512 million people, the European Union is something of a prized market — and political battleground — for the world’s largest energy exporters, particularly when it comes to natural gas.

Russia has long been the dominant source and supplier of natural gas to Europe’s mass market but the U.S. is looking to challenge Russia by stepping up its imports of U.S. liquefied natural gas (LNG) — gas which is super-cooled to liquid form — making it easier and safer to store and transport.

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Europe certainly appears keen to wean itself off Russian gas, and all the geopolitical implications that reliance entails, while making overtures to the U.S. Last July, European Commission President Jean-Claude Juncker and President Donald Trump agreed to strengthen U.S.-EU strategic cooperation with respect to energy and the EU said it would import more LNG from the U.S. “to diversify and render its energy supply more secure.”

Twenty-four percent of U.S. LNG went to the EU in October 2018, a month which saw the largest volume ever of EU-U.S. trade in LNG of almost 0.6 billion cubic meters. In the whole of 2017, only 10 percent of U.S. LNG exports went to the EU. The Commission, the EU’s executive arm, expects U.S. gas exports to the region could double by 2022 and has vaunted the construction of LNG terminals across Europe.



“The fact is that U.S. LNG, if priced competitively, can play and increasing role in EU gas supply, enhancing diversification and EU energy security,” the EU said in a document detailing the state of EU-U.S. LNG trade in late November.

US vs Russian gas. The U.S. became a net natural gas exporter in 2017 for the first time in almost 60 years, according to the country’s Energy Information Administration (EIA). It saw exports of its LNG rise 58 percent through the first half of 2018, compared with the same period in 2017. In fact, while U.S. LNG exports have continued to grow in 2018, U.S. natural gas pipeline import and export volumes have either remained relatively flat or declined from 2017 levels, the EIA noted.

U.S. exporters looking to Europe have a big obstacle in the region, however, and that’s Russia. Russia remains the largest supplier of natural gas to the EU in 2018, according to the Commission’s latest data on EU imports of energy products in October. The other main suppliers are Norway and, at a lower level, Algeria and Qatar.

Showing the extent of much of the EU’s reliance on Russian gas, the Commission noted that 11 member states (Bulgaria, Czech Republic, Estonia, Latvia, Hungary, Austria, Poland, Romania, Slovenia, Slovakia and Finland) imported more than 75 percent of total national imports of natural gas from Russia in 2018, largely due to their proximity to the country.

Gas from Russia is supplied to the continent by state-owned gas company Gazprom via pipelines, giving it an advantage in terms of cheaper transportation costs and established infrastructure and supply. It has a number of major pipelines in operation, or under construction, with European energy and infrastructure companies.

As well as the Nord Stream pipeline and its expanded version, Nord Stream 2, linking Russia to Europe via the Baltic Sea (the expanded pipeline is seen as a way to bypass transit countries like Ukraine), Gazprom and partner companies in Poland, Belarus and Germany oversee the 2,000 kilometer Yamal-Europe pipeline that sends gas from one of its production centers in Torzhok (via Belarus and Poland) to Germany. The company is also constructing the TurkStream pipeline for gas exports from Russia across the Black Sea to Turkey and south eastern Europe.

Geopolitics. Pipeline projects have prompted criticism in Europe and in the U.S., with Trump accusing Germany (the largest foreign buyer of Russian gas) of being “captive” to Russia. His former Secretary of State Rex Tillerson said earlier in 2018 that Nord Stream 2 undermined Europe’s energy security.

Despite its reliance on Russia for gas, the EU’s relationship with the country is a rocky one. Relations deteriorated when Russia annexed Crimea from Ukraine in early 2014 and supported a pro-Russian uprising in east Ukraine, after which the U.S. and EU placed sanctions on Moscow.

Penalties were placed on Russian oil companies (including Gazprom and its oil arm Neft) in 2014 that sought to hinder these companies exploration and production of energy. The U.S. warned in November it could still seek to thwart the Nord Stream 2 project with further sanctions (essentially fines) on companies involved in the project.

Five EU companies are involved in the construction of Nord Stream 2 and the EU has expressed concern over such sanctions. Given Russia’s established and growing infrastructure in Europe, commodity strategists like RBC Capital Markets’ Christopher Louney said the geopolitical dimension to the U.S. promotion, and European adoption, of LNG is hard to ignore.



“There is definitely a geopolitical nature to it (the competition for European LNG customers),” Louney told CNBC Monday. “The geopolitical nature of the U.S. gaining market share in European gas is highlighted by Trump’s opposition to Nord Steam 2 (I’d note that there is also some more critical debate happening in Germany itself now).”

While there are other reasons to increase imports from the U.S. right now, including having a diversity of supply source and pricing, “it’s hard to argue against geopolitics being at play here as well,” he said. Louney believes there’s a long way to go before Russia’s natural gas dominance is challenged, however.

“Europe taking U.S. LNG and U.S. LNG challenging Russian pipeline supplies for dominance are two very different things,” he noted. “Europe has already taken U.S.-sourced LNG over the past two years with just a couple of export terminals in operation (i.e. U.K., Netherlands, Italy, Spain, Portugal etc.).”

“With more U.S. export facilities coming online, the number of takers and volume taken can both increase, but there is a long way to go to compete (with Russia) for pre-eminence,” he said. “That said, Europe’s imports will likely grow leaving room for the U.S. to send additional volumes given the growth of exports here in the U.S.”

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More News On Liquefied Natural Gas (LNG). President Vladimir Putin opened Russia’s first liquefied natural gas (LNG) floating storage and regasification unit (FSRU) on Tuesday, saying it bolsters the country’s energy security.

The Marshal Vasilevskiy FSRU has been set up in Kaliningrad, wedged between European Union members Poland and Lithuania, by Russian energy giant Gazprom (MM:GAZP) to bypass pipeline gas deliveries via Lithuania in case transit is disrupted.

Moscow’s decision to set up the FSRU was in part to reduce gas transit risks to Kaliningrad, home to a Baltic Fleet base, as the EU steps up efforts to reduce its dependency on Russia, a Kremlin-published transcript of Putin’s speech said.



“In recent years we have paid much attention to energy supplies, to the energy of the region as a whole, including in connection with EU plans to remove the Baltic states from Russia’s energy ring,” Putin said.

“This is their (EU countries’) business. Additional tax payers’ money will be invested into that.” Gazprom CEO Alexei Miller told the Interfax news agency that supplies to Kaliningrad from Lithuania had been completely halted on Tuesday and replaced with natural gas from the FSRU.


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The FSRU, the first of its kind in Russia which arrived from Singapore last month with a cargo on board to commission the LNG import facility, can provide Kaliningrad with 2.7 billion cubic meters (bcm) of gas a year, Gazprom has said. LNG is delivered by tankers, meaning it can be supplied to many markets.

World’s largest floating LNG platform starts production in Australia


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Royal Dutch Shell said on Wednesday it has begun output at its Prelude floating liquefied natural gas (FLNG) facility in Australia, the world’s largest floating production structure and the last of a wave of eight LNG projects built in the country over the last decade.

Though the project started up later and cost more than originally estimated, it is expected to further cement Australia’s lead as the world’s biggest LNG exporter, after the country took the crown in November.

In a statement, Shell said wells have now been opened at the Prelude facility, located 475 kilometers north-north east of Broome in western Australia. This means Prelude has now entered start-up and ramp-up, the initial phase of production where gas and condensate – which is an ultra-light form of crude oil – is produced and moved through the facility.

Prelude is expected to have an annual LNG production capacity of 3.6 million tonnes, 1.3 million tonnes a year of condensate and 400,000 tonnes a year of liquefied petroleum gas (LPG).


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Shell did not immediately respond to a Reuters query on when first LNG will be exported from the facility, but analysts estimate exports to start by early next year, with condensates likely to start first.

“First LNG cargo is still several weeks assuming all proceeds as planned, but the timing of first cargo and pace of ramp-up is still subject to technical risk,” said Saul Kavonic, energy analyst at Credit Suisse in Sydney.

“Given Prelude’s novelty, geographic conditions and challenges, it may be subject to greater risk to timeline from wellhead production to first cargo than an average LNG project,” he said. “We expect Shell to seek to get it done right, rather than rush things.”

Shell owns 67.5 percent of the project, while Japan’s Inpex Corp, Taiwan’s CPC Corp [MOEATA.UL] and Korea Gas Corp hold the rest of the shares. Australia overtook Qatar as the world’s largest exporter of LNG for the first time in November, after the start-up of a number of export projects over the past three years, most recently the Ichthys facility.


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The start-up of Prelude, following the ramp-up in production at Ichthys and Russia’s Yamal LNG is expected to put pressure on the Asian market next year, said Kittithat Promthaveepong, a senior analyst at FGE.

Qatar Petroleum to invest $20 billion in U.S. over the coming few years, after the Gulf Arab state unexpectedly quit OPEC this month


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Qatar Petroleum (QP) is looking to invest at least $20 billion in the United States over the coming few years, its chief executive told Reuters, after the Gulf Arab state unexpectedly quit OPEC this month.

Saad al-Kaabi, who holds the energy portfolio of the world’s top liquefied natural gas (LNG) supplier, also said on Sunday the company aimed to announce foreign partners for new LNG trains needed for an ambitious domestic scale-up by the middle of next year, but was keeping open the possibility of going it alone.

Qatar, a tiny but wealthy country is one of the most influential players in the LNG market due to its annual production of 77 million tonnes. It plans to boost capacity 43 percent by 2023-2024 and will be building four liquefaction trains for the LNG expansion.

As part of its more than $20 billion investment push in the U.S. QP is looking “at gas and oil, conventional and non-conventional,” Kaabi said.

Qatar Petroleum is majority owner of the Golden Pass LNG terminal in Texas, with Exxon and ConocoPhillips (N:COP) holding smaller stakes. Kaabi said he expected to make a final decision on that investment and whether to move ahead with the project “by the end of the year, if not January.”

Qatar is a relatively small oil producer compared to its massive gas production. Its decision to quit OPEC this month was seen as a swipe at the group’s de facto leader Saudi Arabia, which along with the United Arab Emirates, Bahrain and Egypt, has imposed a political and economic boycott on Qatar since June 2017, accusing it of supporting terrorism, which Doha denies.


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Kaabi said that proposed U.S. legislation known as “NOPEC”, or No Oil Producing and Exporting Cartels Act, which could open the OPEC group up to anti-trust lawsuits, was among the reasons for quitting the oil exporting club.

Qatar Petroleum announced separately on Sunday that it was partnering with Italian oil major Eni (MI:ENI) on three oil fields in Mexico, taking a 35 percent stake in deposits that will begin production in mid-2019 and ramp up to about 90,000 barrels per day by 2021.

The company is in talks with international oil firms about the LNG expansion project at home, including Eni, Kaabi said. Other partners already operating in Qatar include Exxon Mobil Corp (N:XOM), Total (PA:TOTF), Royal Dutch Shell (L:RDSa) and ENI (MI:ENI).

QP said it will self-finance the LNG expansion rather than borrow, a shift from previous practices where it used lenders to fund up to 70 percent of project costs.

Kaabi said it could carry out the expansion alone if no good offers from foreign firms were made. “We are looking for a lot of things (in our partners) including asset swaps, things that will help me in my international expansion,” he said. “If I don’t get good deals, nobody will come.”

The company currently pumps 4.8 million barrels of oil equivalent per day (boed) and aims to boost its output to 6.5 million boed in the next 8 years by expanding its upstream business abroad.


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Russia is seeking to boost its power in Europe and grip over Ukraine with the proposed Nord Stream 2 natural gas pipeline

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Russia is seeking to boost its power in Europe and grip over Ukraine with the proposed Nord Stream 2 natural gas pipeline, the top U.S. energy diplomat said on Monday, in a step-up of Washington’s rhetoric against the pipeline.

“Through Nord Stream 2, Russia seeks to increase its leverage of the West while severing Ukraine from Europe,” Francis Fannon, the U.S. assistant secretary for energy resources at the State Department, told reporters in a teleconference.

The pipeline has been opposed both by President Donald Trump, a Republican, and his Democratic predecessor Barack Obama as a political tool for Russia to consolidate power over Europe.

Much of the gas that Europe currently gets from Russia via pipeline goes through Ukraine, which collects billions of dollars in transit charges making up to 3 percent of its gross domestic product.



If Nord Stream 2, which aims to bring Russian gas to Western Europe via the Baltic Sea, and TurkStream, a pipeline to bring gas from Russia to Turkey, are completed it would mean transit revenues would evaporate,

“It’s kind of just what’s left over that would be transited, potentially transited, through Ukraine,” Fannon said. “Even then that’s only based on whether we can trust (Russia President Vladimir) Putin, I don’t think the record should indicate anyone should.”

Putin has said that Nord Stream 2, a consortium of Russia’s state-controlled Gazprom (MCX:GAZP) and five European companies, is purely economic and not directed against other countries. Russian gas could continue to go through Ukraine if the pipeline is completed, Putin has said.

But Russia has stopped shipments of gas to Ukraine in winter in recent years over a series of pricing disputes. Critics of Nord Stream 2 say it could increase Russia’s ability to manipulate European energy markets. In an increase in tensions, Russia last month seized three Ukrainian naval ships off the coast of Russia-annexed Crimea in the Sea of Azov after opening fire on them.

Germany’s foreign minister, Heiko Maas, said this month that Berlin will not withdraw its political support for Nord Stream 2 and that German Chancellor Angela Merkel had secured a pledge from Putin in August allowing gas shipments across Ukraine’s territory.

Fannon made his comments after traveling to Eastern Europe to discuss projects that could offer Europe a more diverse natural gas supply. Those included a floating liquefied natural gas terminal on the Adriatic island of Krk that could one day receive gas imports from the United States, which is increasing its exports of the fuel, or the eastern Mediterranean.



Fannon said he expected Russia’s aggression in the Sea of Azov to boost support for several bills in the U.S. Congress that include new sanctions on Russia’s energy sector, though he refrained from commenting on any particular legislation.

Eni (MI:ENI) is in talks to grow its footprint in Oman and the United Arab Emirates


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Eni (MI:ENI) is in talks to grow its footprint in Oman and the United Arab Emirates as part of plans to build its asset base in the oil-rich Gulf and offset its reliance on Africa, a source close to the matter said. The international oil company has a limited presence in the Middle East, where some of the world’s biggest oil and gas reserves lie, producing more than half its output in Africa.

“Eni is in talks with Oman for various opportunities,” the source told Reuters, adding recent geopolitical tensions in the area had not curbed its interest. Last year Eni sealed its first deal in Oman, winning a majority stake in offshore acreage and selling on part to Qatar Petroleum.

This year it took a first step into Abu Dhabi, paying $875 million for stakes in two oil concessions and then buying part of the giant Ghasa gas field from state oil group Adnoc. The source said Eni had submitted an expression of interest for a minority stake in Adnoc’s refinery business, confirming an earlier Reuters report.

Abu Dhabi has put on sale 40 percent of Adnoc’s refining unit valued at $8 billion but will never sell to a single company, the source said, adding many others were interested including Chinese and Indian firms and France’s Total (PA:TOTF).

“Eni is also interested in other downstream opportunities,” the source said, pointing to Adnoc’s ambitions in that area. Last year Adnoc presented a 2030 strategy plan to open up its energy markets to foreign operators and attract the skills needed to develop E&P, refining and petrochemical industries.

Thanks to bumper natural gas discoveries in Mozambique’s Mamba field and Egypt’s Zohr, Eni has one of the strongest discovery records in the industry and one of the fastest time to market records. “Getting into refining would give Eni a natural hedge to all its upstream business as well as allowing it to diversify away from Africa,” said Santander (MC:SAN) oil analyst Jason Kenney.

Sources have also told Reuters Eni is in the race to get into Qatar’s plans to expand its liquefied natural gas industry, saying teaming up with Qatar Petroleum in Mexico was a preparatory move.


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More News and Analysis On Natural Gas


 


The U.S. Energy Department‘s weekly inventory release showed a smaller-than-expected decrease in natural gas supplies. While prices fell slightly following the lower inventory drawdown, the fuel remains buoyed with forecasts of colder-than-normal weather in the face of relative deficit in inventories for this time of year. Having hit a a four-year high of $4.837 per MMBtu recently, there is potential for further price gains with bulk of the winter heating season still to come.

Stockpiles held in underground storage in the lower 48 states fell by 59 billion cubic feet (Bcf) for the week ended Nov 23, below the guidance (of 73 Bcf decline) as per the analysts surveyed by S&P Global (NYSE:SPGI) Platts. However, the decrease was higher than both the five-year (2013-2017) net shrinkage of 49 Bcf and last year’s drop of 35 Bcf for the reported week.

Following past week’s supply decline, the current storage remains well below benchmarks. At 3.054 trillion cubic feet (Tcf), natural gas inventories are 720 Bcf (19.1%) under the five-year average and 644 Bcf (17.4%) below the year-ago figure.

Fundamentally speaking, total supply of natural gas averaged around 92.9 Bcf per day, up slightly on a weekly basis as production and Canadian imports edged up. Meanwhile, daily consumption remained essentially unchanged at 84.2 Bcf.

Natural Gas Up More than 50% So Far This Year. As a result of the headline miss, natural gas prices lost 1.1% yesterday to settle at $4.646 per MMBtu. Despite the temporary blip, the fuel’s demand-supply situation remains favorable. In fact, prices are up around 55% year-to-date on cold weather demand and slumping supplies, in the process hitting their highest levels since November 2014.

Natural gas recently broke the $4 per MMBtu mark for the first time in four years with cooler weather conditions resulting in strong demand for the heating fuel. Despite skyrocketing production, natural gas entered the winter season with stockpiles at their lowest in 15 years. If the current (2018-2019) winter turns out to be colder than normal, the surge in expected demand — in the face of relative deficit of natural gas inventory — could trigger a bigger rally in the commodity’s price.

The fundamentals of natural gas continue to be favorable in the long run, considering the secular shift to the cleaner burning fuel for power generation globally and in the Asia-Pacific region in particular.

The EIA predicts global demand for the commodity to grow 43% from 2015 to 2040. Countries in Asia and in the Middle East – led by China’s transition away from coal – will account for most of this increase. The replacement of coal-fired power plants and higher consumption from industrial projects have also contributed to the strength in natural gas demand.

Want to Own Natural Gas Stocks?. The secular tailwinds mentioned above could see natural gas eventually settle above the $5 per MMBtu mark before the end of the winter. This augurs well for natural gas-heavy upstream companies like Gulfport Energy Corporation (NASDAQ:GPOR) , Antero Resources (NYSE:AR) , Cabot Oil & Gas Corporation (NYSE:COG) , QEP Resources Inc. (NYSE:QEP) and SilverBow Resources, Inc. (NYSE:SBOW) .

Russia is expanding its foothold in the fast-growing natural gas market despite Western efforts to limit Moscow’s energy influence


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The New Geopolitics of Natural Gas


Directly squaring off against U.S. shale exporters, Russia has emerged this year as a major player in the burgeoning market for liquefied natural gas, which is exported across the oceans on special ships. Meanwhile, Russia has been pumping gas into Europe at a record pace in existing pipelines, and to the East it’s close to opening a major pipeline into China, the world’s fastest-growing major gas market.

Natural gas, a vital energy source for homes, factories and power plants, is the world’s fastest-growing fossil fuel. Supplying it to the West, and increasingly to Asian powers like China and India, gives Russia hard cash and a seat at the geopolitical table.

“Our main goal is to preserve our current markets, primarily Europe, and to gain a foothold in new ones, especially Asia,” said Alexey Teksler, Russia’s first deputy Minister of Energy in an interview at his Moscow office. A giant map of Russia’s gas connections to Europe and Asia covered one wall.

Washington has been looking to curb Russia’s expansion, pressuring Berlin to halt construction of Nord Stream 2, a major gas pipeline connecting Germany with Russia. The U.S. has used trade negotiations to squeeze promises from the European Union and Asian countries to buy more U.S. gas.

But so far, only a handful of U.S. gas cargoes have reached European shores. In an investor presentation earlier this year, Russian state-owned energy giant Gazprom illustrated U.S. gas exports into Europe as a few drops of water beside a steaming teacup that depicted Russian exports.

In June, India received its first shipment of Russian LNG under a $25 billion contract, having previously imported U.S. gas. China recently imposed tariffs on U.S. LNG, which could also provide an opening for Russia to supply it with more gas.

“They’ve ramped up their efforts. It looks like Russia’s ambitions are being realized bit by bit,” Tim Boersma, a researcher at Columbia University’s Center on Global Energy Policy.

Oil and gas brings in around 40% of Russia’s budget revenues, and a good chunk of that comes from the country’s 35% share of the European gas market.

Two years ago, when the first cargoes of U.S. LNG left a Louisiana terminal for Europe, European politicians predicted that this dominance was set to end in a wave of new gas from American shale fields, as well as from Qatar, the world’s largest gas producer.

Around the same time the EU imposed regulations on Moscow’s gas infrastructure. It later settled an antitrust case against Gazprom, Russia’s biggest gas exporter, that clinched promises of cheaper and freer natural-gas flows.


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Russia has quickly adapted to the restrictions and new competition. It’s increasingly moving to auctions, where gas is offered to the highest bidder, and away from its traditional model of locking customers into long-term contracts linked to oil prices. That has given its customers more flexibility and lowered their prices.

Price has been Russia’s competitive advantage. The June delivery to India, the first under a 20-year deal, was priced at around $7 per million British thermal units, around $1 to $1.50 cheaper than comparable deliveries from Qatar or the U.S., analysts say.

The Gazprom price “is very competitive,” Indian oil minister Dharmendra Pradhan told Indian media in June as he watched the giant tanker LNG Kano dock in the West Indian port of Dahej.



The industry in Russia has its own challenges. There are currently about six LNG projects in development or on the drawing board in Europe, most of them in countries that are in Russia’s former sphere of influence, that can turn to gas shipments from the U.S. and Qatar, analysts say.