NEW YORK (Reuters) – The bright lights of New York City may burn a little cleaner next year, when the first major natural gas pipeline in a generation is built to connect the largest U.S. metropolis to new energy-producing regions across the country.

Spectra Energy’s controversial $1.2 billion pipeline, which received approval from the Federal Energy Regulatory Commission (FERC) on Monday, has met with stiff opposition from local communities, but is seen as a key to reduce New York’s reliance on dirtier oil-based fuels.

The 20-mile (32-km) line, which will connect New York to neighboring New Jersey, will deliver about 800 million cubic feet of natural gas per day to homes and businesses across the city from prolific shale deposits in Pennsylvania and southern states whose rapid development over the last five years has transformed the U.S. energy outlook.

“This approval clears the way for a much-needed new natural gas supply in the New York City region,” New York’s deputy mayor for operations, Cas Holloway, said on Tuesday.

While the densely populated U.S. Northeast is the biggest heating oil market in the world, New York City is phasing out higher-polluting fuels in favor of the country’s growing supply of natural gas.

One of the dirtiest grades of fuel oil — No. 6 — will no longer be used in New York by 2015, under city regulations. A halving in the use of fuel oil by 2013 could save about 120 lives a year, according to the mayor’s office, but requires more infrastructure if natural gas is to take its place.

And while natural gas offers a potential reduction in pollution, it is also much cheaper, given rocketing shale production. On Monday, fuel oil was priced around $16.50 per million British thermal units in New York Harbor. Natural gas at the New York citygate was $2.70 per mmBtu.

NEW YORK, May 15 (Reuters) – Two North American liquefied natural gas export plants were announced on Tuesday, joining a lengthening list of projects aimed at shipping surplus gas overseas.

Excelerate Energy, the U.S. liquefied natural gas company founded by Oklahoma billionaire George Kaiser, plans to develop the country’s first floating LNG export plant off the Gulf Coast, while energy major Royal Dutch Shell has partnered with Asian buyers to build a plant in western Canada.

The two projects add to 10 others announced in North America over the last few years as a huge supply surge from shale deposits floods the market and pushes prices far below levels in Europe and Asia.

The export of LNG, which is natural gas cooled to a liquid for shipping, marks a stark turnaround for North American energy companies, which 10 years ago were scrambling to build import terminals before shale gas production unlocked potentially decades of supplies.

It has sparked a political debate in the United States about exporting cheap resources that could be used domestically. The Obama administration said on Mo nday that it does not oppose U.S. LNG exports, though it will depend on an official analysis to guide its decision on whether to allow more gas projects to proceed.

But Canada, whose vast gas reserves are stranded without demand from the amply-supplied United States, is racing to find needy buyers in Asia willing to pay dearly for the fuel. LNG prices in Asia are at four-year highs of about $18 per million British thermal units (mmBtu), while U.S. benchmark prices languish around $2.50 mmBtu, weighed down by oversupply.

Already in Canada the Kitimat LNG project and the BC LNG Co-op have export licenses in place. In the United States, only Cheniere Energy’s Sabine Pass project has full export approval.

NEW YORK (Reuters) – Excelerate Energy, the U.S. liquefied natural gas company founded by Oklahoma billionaire George Kaiser, said on Tuesday it will develop the country’s first floating LNG export plant off the Gulf Coast, joining a queue of projects awaiting government approval to ship out surplus gas.

The Lavaca Bay LNG project off Texas, expected to start exporting by 2017, would initially have the capacity to ship 3 million to 4 million metric tons per year (mtpa) of LNG, Excelerate said in a statement. It could be expanded to 8 mtpa, or about 1 percent of daily U.S. supply.

The relatively small size of the floating liquefaction project compared to an onshore site could speed up construction, which is expected to take just 44 months, according to Excelerate. Most LNG projects take at least four years to build.

Privately-held Excelerate will become the eighth company awaiting approval from the Department of Energy to ship cheap U.S. natural gas to higher-priced markets across the globe. Record domestic gas production from newly developed shale deposits has pushed prices far below levels in Europe and Asia, reversing a rush to import LNG into projects to export the gas over the last five years.

The Obama administration said on Monday that it does not oppose LNG export, though it will depend on an official analysis to guide its decision on whether to allow more gas projects to proceed. Only Cheniere Energy has so far been granted license to sell gas to major buyers, like China, which do not have free trade pacts with the United States.

The plans, if all were approved, could together export about 16 percent of U.S. daily production, raising concern from consumer groups and politicians about the effect that exporting might have on domestic prices.

LNG is natural gas cooled to a liquid for transport overseas.

NEW YORK (Reuters) – Chesapeake Energy reported that natural gas production was almost unchanged in first quarter of this year compared to late 2011, confirming fears that pledges to cut output have so far failed to stem a flood of supply.

The No. 2 gas producer said it planned to extend those curbs throughout the year to counter a huge gas glut that pushed prices to ten-year lows. It said curtailments would total some 50 billion cubic feet (bcf) for the rest of the year after cutting output by 30 bcf in the first quarter.

Despite curbs imposed in February and March, however, the firm still produced 271 (bcf) in the quarter versus 272 bcf in the fourth quarter of 2011, bearing out worries that rapid growth in output from new wells would offset any reductions. Production rose from 243 bcf in the same period last year.

Chesapeake was the first driller to cut output this year. Other companies followed, but Chesapeake’s curbs accounted for the lion’s share, about a tenth of its daily output.

Still, traders have been dubious about whether the curbs would be sufficiently deep, or implemented for long enough, to ease oversupply and bolster prices.

“As a result of reduced drilling activity in 2012 and 2013 on its dry natural gas plays, Chesapeake is projecting a decline in its natural gas productive capacity in 2013 of approximately 12 percent after adjusting for estimated net voluntary production curtailments of approximately 80 bcf in 2012,” the company said in its earnings statement.

The curtailments it reported were broadly in line with its January 23 announcement that it would cut gross production by 0.5 billion cubic feet per day (bcfd). By February 21 it had deepened the curtailments to 1 bcfd. But the overall figures show cuts were not as significant as some had hoped.

NEW YORK, May 1 (Reuters) – Chesapeake Energy reported that natural gas production was almost unchanged in first quarter of this year compared to late 2011, confirming fears that pledges to cut output have so far failed to stem a flood of supply.

The No. 2 gas producer said it planned to extend those curbs throughout the year to counter a huge gas glut that pushed prices to ten-year lows. It said curtailments would total some 50 billion cubic feet (bcf) for the rest of the year after cutting output by 30 bcf in the first quarter.

Despite curbs imposed in February and March, however, the firm still produced 271 (bcf) in the quarter versus 272 bcf in the fourth quarter of 2011, bearing out worries that rapid growth in output from new wells would offset any reductions. Production rose from 243 bcf in the same period last year.

Chesapeake was the first driller to cut output this year. Other companies followed, but Chesapeake’s curbs accounted for the lion’s share, about a tenth of its daily output.

Still, traders have been dubious about whether the curbs would be sufficiently deep, or implemented for long enough, to ease oversupply and bolster prices.

“As a result of reduced drilling activity in 2012 and 2013 on its dry natural gas plays, Chesapeake is projecting a decline in its natural gas productive capacity in 2013 of approximately 12 percent after adjusting for estimated net voluntary production curtailments of approximately 80 bcf in 2012,” the company said in its earnings statement.

The curtailments it reported were broadly in line with its Jan. 23 announcement that it would cut gross production by 0.5 billion cubic feet per day (bcfd). By Feb. 21 it had deepened the curtailments to 1 bcfd. But the overall figures show cuts were not as significant as some had hoped.

NEW YORK (Reuters) – For U.S. natural gas producers, it’s the credit crisis all over again.

As prices of the fuel tumble to their lowest in ten years, big lenders are set to slash credit lines to the most exposed producers by as much as a quarter, forcing firms to conserve cash by cutting back on drilling plans or to sell assets.

As part of a twice-yearly process of reassessing more than $60 billion dollars in loans to the energy sector, bankers are already telling some mid-sized outfits like Penn Virginia Corp and Carrizo Oil and Gas to expect some of the biggest cuts since the financial crisis in 2008, according to interviews with more than a dozen lenders and producers.

“It could get nasty out there,” said one loan manager involved in the bi-annual “redeterminations” process during which banks consider how much capital they will extend to energy companies based on forward commodity prices, a company’s production outlook and its hedging program.

The current round of lending curbs, due to be completed within the next few weeks, may not cut so deep at companies that can pivot away from gas production and drill for more lucrative oil, which is trading at a record high relative to gas. And others have tapped less than half their credit lines, leaving some cushion to absorb a reduction without distress.

There are also large debt-laden companies like Chesapeake Energy that tend to rely more on longer term debt by borrowing through the bond market, giving them some protection from the bank credit process.

But redeterminations can provide — or choke off — the life blood of smaller companies. If the surge in shale gas production continues to depress prices six months from now, an even more painful round of curbs could follow for companies that produce mainly natural gas or whose production is largely unhedged.

NEW YORK, April 25 (Reuters) – For U.S. natural gas producers, it’s the credit crisis all over again.

As prices of the fuel tumble to their lowest in ten years, big lenders are set to slash credit lines to the most exposed producers by as much as a quarter, forcing firms to conserve cash by cutting back on drilling plans or to sell assets.

As part of a twice-yearly process of reassessing more than $60 billion dollars in loans to the energy sector, bankers are already telling some mid-sized outfits like Penn Virginia Corp and Carrizo Oil and Gas to expect some of the biggest cuts since the financial crisis in 2008, according to interviews with more than a dozen lenders and producers.

“It could get nasty out there,” said one loan manager involved in the bi-annual “redeterminations” process during which banks consider how much capital they will extend to energy companies based on forward commodity prices, a company’s production outlook and its hedging program.

The current round of lending curbs, due to be completed within the next few weeks, may not cut so deep at companies that can pivot away from gas production and drill for more lucrative oil, which is trading at a record high relative to gas. And others have tapped less than half their credit lines, leaving some cushion to absorb a reduction without distress.

There are also large debt-laden companies like Chesapeake Energy that tend to rely more on longer term debt by borrowing through the bond market, giving them some protection from the bank credit process.

But redeterminations can provide — or choke off — the life blood of smaller companies. If the surge in shale gas production continues to depress prices six months from now, an even more painful round of curbs could follow for companies that produce mainly natural gas or whose production is largely unhedged.

April 16 (Reuters) – U.S. regulators on Monday approved the country’s first liquefied natural gas export plant in nearly 50 years, which will open up cheap and abundant American supplies to importers across the globe.

The Federal Energy Regulatory Commission (FERC) approval paves the way for construction to begin at Cheniere Energy’s LNG plant at Sabine Pass, Louisiana, which will chill natural gas to a liquid for shipping overseas by as early as 2015.

It marks a huge turnaround for the U.S. energy market that five years ago was scrambling to build gas import terminals before shale gas drilling provided decades of domestic reserves. Analysts say the project alone will do little to alleviate the glut in supplies that have sent domestic prices to 10-year lows, however.

The FERC ruling comes as U.S. natural gas inventories are set to spill over due to record high production from newly developed gas deposits.

A string of export projects have been proposed in the United States to supply thirsty markets in Europe and Asia where gas prices are up to seven or eight times higher.

For now, Cheniere looks likely to be the only project to get the go ahead. The U.S. government has suspended decisions on expanding U.S. gas exports until a study on the price impact of such exports on domestic consumers is completed late summer.

U.S. natural gas prices dropped below $2 per million British thermal unit this month for the first time since 2002, easing fuel costs.

NEW YORK (Reuters) – U.S. natural gas markets bracing for an autumn price crash caused by overflowing storage may be in for a shock this summer.

Some regions unable to cope with rocketing production are set to fill up by July, leaving a glut of stranded gas that could send already depressed prices into an unprecedented tailspin much earlier than expected.

The 4.1-trillion-cubic-feet U.S. storage system comprises three separate storage regions — the east, west and south. Total capacity is unlikely to fill up until October. Still, if just one oversupplied region reaches capacity, the resulting cavern closures and pipeline restrictions could send shockwaves across the whole U.S. market, prompting a sharp fall in next-day gas prices of the likes not seen before.

Based on last year’s injection rates, the relatively isolated 1.3-tcf producing region storage system in Louisiana, Texas and the surrounding states could be the first to top up, four months before the end of the injection season in November.

The region, which serves the south’s major producers, is hundreds of miles from consuming hubs in the northeast and midwest. Current price spreads make it too expensive to ship gas out of that area, potentially leaving stranded gas in the south.

“The moment of truth could be coming much earlier in the producing region, possibly by mid-summer,” said Dominick Chirichella, senior partner at Energy Management Institute.

When storage restraints and pipeline flow restrictions were announced in the producing region in 2009, price points in the nearby Rockies slumped to 13 cents per million British thermal units within day — a fraction of benchmark prices at the time. And at that time, the situation was not as dire as it is now.

NEW YORK, March 28 (Reuters) – Owners of some U.S. natural gas storage sites began turning some customers away this week for fear that the system will overflow in autumn, the clearest sign yet that surging production may wreak havoc in the market later this year.

Huge supplies of shale gas from newly exploited deposits are set to fill U.S. storage caverns and tanks to their limit this year for the first time ever, threatening to force producers to shut down wells or risk overloading the pipeline network.

Signs of the strain became evident this week, as storage operators rejected some supplies in order to ensure they have sufficient space to meet all of their contractual commitments over the summer. Gas inventories typically fall during the winter and rise in summer, and storage companies usually sell much of their capacity months or years in advance.

TransCanada’s ANR Storage, one of the country’s biggest storage owners, halted gas injection services indefinitely for interruptible clients this week, “due to storage field constraints”, a notice on its website said.

Normally operators do not turn back interruptible customers, whose contracts give the storage firm the option to reject deliveries to make room for firm summer customers, until much later in the year, when gas levels are higher.

But storage sites across the country are at their fullest ever for March, when stocks are usually at a low ebb after winter drawdowns. One of the mildest winters on record has pushed stocks more than 50 percent above normal for this time of year, increasing the potential that capacity will fill up early.

Interruptible customers, including gas marketers playing the spreads or producers looking for extra short term space, only make up a small slice of total storage customers. But restrictions on their storage use in March gives an inkling of the limitations that the market will face later this year.