_

Louisiana’s petrochemical industry is in a renaissance period due to low natural gas prices and major discoveries, including northwest Louisiana’s Haynesville Shale, a chemical industry executive said Wednesday.

Dan Borné, president of the Louisiana Chemical Association and the Louisiana Chemical Industry Alliance, told the Rotary Club of Baton Rouge that the industry was in perilous times just five years ago.

The price of natural gas, a fuel and feedstock for the chemical industry, was high. Many ammonia plants had shut down and Louisiana chemical plants along the Mississippi River and Interstate 10 corridor from Baton Rouge to New Orleans had cut back. Chemical companies found it more advantageous to open and expand overseas.

Employment in the industry had fallen from 34,000 in 1999 to 24,000 only 10 years later.

“We were really in a pickle,” Borné said. “We weren’t really sure where we were gonna end up.”

But Borné credited “the magic of the marketplace,” in the form of falling natural gas prices and development of the Haynesville Shale for bringing the good times back.

Borné said that because the chemical industry uses natural gas the way a bakery uses flour — for everything it makes, essentially — Louisiana’s industry is at its strongest when the price of oil per barrel is seven times the price of natural gas per million British thermal units.

Today, gas is roughly $3 per MMBTUs, while oil is about $90 per barrel — about a 30-to-1 ratio.

“That makes Louisiana incredibly competitive,” he said.

Borné said there is a lot of activity in the chemical industry, which has added 1,000 jobs a year for the last three years. He said Methanex is going to dismantle a methanol plant in Chile and move it to Geismar and is considering another facility in Geismar.

He said Cornerstone Chemical is doing a $30 million feasibility study on building an $800 million ammonia plant in Jefferson Parish.

Even the railroad is expanding in the state — in particular, Union Pacific is laying track.

“When they start laying track, they’re betting on a strong economy,” Borné said.

The industry is going to need thousands of construction workers for expansions and new plants.

“This is an exciting time for our industry,” he said.

But Borné warned that competition remains stiff from China, Malaysia and other Asian nations, not to mention other states like Texas, Pennsylvania, Ohio and West Virginia, which are developing shale plays of their own.

He said fair, consistent regulation; a less litigious legal climate; strong infrastructure; and a well-prepared workforce are keys to competing.

original article

_

Despite worldwide moratoriums on fracking of new wells, natural gas prices continue to hover around $3 per MMBtu, up from a frighteningly low $2 per MMBtu. The natural gas industry it seems has outsmarted itself and overproduced while at the same time a global economic slowdown is reducing demand. This chart from the US Energy Information Administration shows a clear inverse relationship between domestic production and price.

Earlier this year Chesapeake Energy (CHK) announced that it might reduce production by cutting its natural gas rig count, and they’re not the only ones to do so. Overall natural gas rig counts began dropping slightly in the first half of 2012. Notice however, that the percentage of new rigs being deployed to extract natural gas has been steadily losing ground to oil rigs since prices peaked in 2008.

What boggles my mind is the lack of consumption in response to incredibly low natural gas prices. As the price of natural gas has fallen from a peak of roughly $10 MMBtu in 2008 to a low of about $2 MMBtu earlier this year total consumption in the US has been nearly flat. Assuming the second half of 2012 matches the first, we can expect total natural gas consumption in the US to reach just under 25,934 billion cubic feet. That is an 11.4% increase over 2008′s total consumption, which seems like a lot until you consider that the price of natural gas fell about 500% during that same period.

In the US, the biggest increases in natural gas usage are coming from electricity generation while vehicle usage has sadly remained flat.

The demand for natural gas in the United States might be stuck in the mud, but globally the usage of natural gas is blowing up. This is largely due to the popularity of using compressed natural gas as a vehicle fuel. Toyota (TM), General Motors (GM) and other automakers produce versions of their vehicles with factory installed compressed natural gas tanks and gasoline. The gasoline is used sparingly to provide power when the driver steps on the accelerator and the much cheaper natural gas makes cruising very inexpensive.

In addition to factory production models, retrofitting a gasoline vehicle with a CNG or liquefied propane gas tank can be done for less than a thousand dollars. In Thailand, where I spend most of my time, the cost of retrofitting a vehicle to run on CNG is recouped after driving about 10,000 km; consequently demand for natural gas in Asia is wildly outpacing that of the US.

Popular passenger vehicles that run on both compressed natural gas and conventional gasoline are widely available, and popular throughout Asia.

The US should eventually catch up to the developing world’s usage of CNG vehicles. In the meantime I think the best opportunities for investors to profit from advanced natural gas extraction techniques in the US will come from exporting liquefied natural gas.

Unfortunately the amount of natural gas exported by the US will remain right where it is until after the November elections. Many state lawmakers are pressing the Obama administration to allow more natural gas to be liquified and shipped overseas. According to Secretary of Energy Steven Chu, the administration is hesitant to allow more natural gas to be exported to foreign countries, like China, because they do not want to be responsible for higher prices at home. I’m sure that they are far more concerned about the Romney campaign distorting a decision to export more fossil fuels as an act of treason. I’m sure that soon after elections, exports of natural gas will be allowed to rise.

Cheniere Energy, Inc. (LNG) is betting the farm on future natural gas exports. Their Sabine Pass Liquefaction project is well underway and a new LNG terminal is to be built in Corpus Christi. So far, Cheniere is the only US company allowed to export LNG to countries without free trade agreements, albeit in limited quantities. India’s largest gas transmission company, GAIL signed a 20 year agreement with Cheniere to buy 3.5 million tons of LNG per year. A lift on export restrictions would almost certainly result in more contracts for Cheniere from India and other gas hungry nations.

Cheniere has had an incredible run up over the last two years. If liquified natural gas exporting restrictions are eased, the run up should continue.

Relying on favorable policy and commodity prices is risky business to say the least. Furthermore, Cheniere has posted negative earnings 5 quarters in a row. If you want to make a bet on Cheniere I strongly suggest a simple call spread. For example:

Buy December 2012 call with a strike of ’16′ (priced at $1.50)

Sell the December 2012 call with a strike of ’18′ (priced at $0.70)

Net debit to start: $0.80

Maximum Profit: $1.20

This trade gives you about a month and a half after the election for the Obama administration to approve, or reject, an increase in natural gas exports. Your upside is limited to $120 per contract, but your risk is limited to only $80 per contract. Even if you hold on to the contracts until the date of expiration you only need a stock price of $16.80 to break even.

original article

_

Asian demand for natural gas has risen so sharply in recent years that Alaska wants to build a $50 billion pipeline and export terminal to move its stranded supply offshore. Exxon Mobil Corp., BP Plc and ConocoPhillips will deliver plans for such a project to Alaska Governor Sean Parnell by the end of this month.

Alaska has the only operating liquid natural gas (LNG) export plant in the United States. It’s an aging facility, capable of processing less than 10 percent of the volume of a new 3 billion cubic-feet-a-day terminal. The state’s hunger for revenues from its conventional gas is part of a larger unsolved question that the U.S. will have to tackle in the next few years: What will the nation do with its newfound abundance of natural gas, mostly from unconventional sources?

The question lurks just under the surface of the national energy conversation, which vacillates between exuberance that shale gas exists at all and fear that the method of extracting it — fracking — is polluting people’s water. The high-pitched debates around fracking largely obscure another player: the rest of the world. It wants less expensive natural gas.

Gas is pricey in much of the world, particularly in energy-poor Japan and South Korea. This map shows why U.S. producers are so eager to construct U.S. export facilities. October prices, in dollars per million BTUs, could reach $13.50 in Argentina and $13.80 in Japan and South Korea — but just $2.48 at the Lake Charles LNG import facility, in Louisiana. It’s so inexpensive stateside because the U.S. supply is so great and because it’s trapped in markets served by North America’s pipeline network.

There’s a simple reason for that disparity, one that will require considerable investment to overcome — if the U.S. decides it wants to. Unlike oil, which flows on and off tankers, and coal, which fills up capesize transport vessels, natural gas just wants to be free. It’s lighter than air and wants nothing so much as to disperse into the atmosphere. Natural gas must be contained before it can be shipped.

It’s a considerable undertaking.

First, a country has to develop gas fields, which the U.S. has done, and build hundreds of miles of pipelines to bring the gas to a port.

Second, it must build the massive port infrastructure to liquefy the gas, by lowering is temperature to about -260 degrees Fahrenheit. The Department of Energy has approved one new LNG export terminal, at Cheniere Energy Inc.’s existing import terminal in Cameron Parish, Louisiana. Nearly a dozen others are under DOE review. Just to give you a sense of how quickly this is all moving, less than 10 years ago the U.S. was expecting to build more import terminals.

Third, a fleet of specialized tankers must be called into service to transport the gas by sea.

Finally, the receiving side must re-gasify the fuel — carefully! — provided that it already has built the pipeline infrastructure to deliver it to customers.

How much should the U.S. spend on gas export infrastructure? If it sells its gas overseas, how much, for example, might future U.S. prices — for U.S. gas — rise as future South Korean prices fall? “That’s what the big discussion is right now,” said Andres Rojas, market analyst at Waterborne Energy Inc., the company that provides the Federal Energy Regulatory Commission with the map data. We spoke by phone late last month.

U.S. producers would like to sell gas in foreign ports, where they can ask a higher price. U.S. utilities, manufacturers, which use gas in an industrial feedstock, and residential and business consumers would like prices to stay low.

Policymakers and business leaders are trying to better understand the relationship between potential U.S. exports and prices at home before they make commitments to build new outbound gas liquefaction terminals. The U.S. Energy Information Administration reported in January that, according to its simulations, more exports would mean higher prices (pdf) for gas and electricity, and some fuel-switching back to coal-fired electricity generation.

A study (pdf) by Rice University’s Baker Institute concluded in August that there’s nothing to guarantee that the world market will always look as enticing for U.S. exports as it does now. Fluctuation in exchange rates, potential foreign gas discoveries and the global price effects from the U.S. increasing world supply could all change the picture in unpredictable ways, the report states, creating risk for exports.

For several years now, the U.S. has both celebrated and fretted over this newly accessible energy source. As the controversy over fracking is gradually resolved, the next question about gas will be, should it stay or should it go?

“As the story plays out,” the Baker Institute study concludes, “the international gas market will evolve into something dramatically different from what it is today.”

original article

_

The natural-gas industry is drowning in its own success.

Drilling companies are extracting so much natural gas from formations like Pennsylvania’s Marcellus Shale that they want to export the fuel overseas, provoking opposition from some who say that American gas should stay at home.

At the Shale Gas Insight conference in Philadelphia last week, Jack Williams, president of XTO Energy, used the podium to promote the idea of exporting liquefied natural gas (LNG) by ships.

“Just as we do with exports of grain, cars, and other American products, by exporting LNG, we can create economic value that would not have existed otherwise,” Williams told the audience.

XTO has a lot to gain from exports.

It is a subsidiary of Exxon Mobil Corp., the nation’s largest producer of natural gas, whose price has plummeted in the last few years because the shale-gas revolution is producing more gas than U.S. markets can absorb.

Exxon Mobil in August submitted an application to the Federal Energy Regulatory Commission to export LNG from a terminal it co-owns in Sabine Pass, Texas. It’s one of seven facilities nationwide seeking federal approval to export.

Producers embrace the idea of exporting natural gas, which would increase demand, boost prices, and spur more production.

Exports would mean more American jobs producing gas. The income would also improve America’s balance of trade.

But proposals to build more LNG export terminals are controversial.

Some American chemical producers fear that shipping LNG to foreign consumers would make gas scarce here, just as the industry is undergoing a revival thanks to abundant supplies of natural gas, a principal raw material.

original article

_

A bit of a gush in oil returns is putting the brakes on gas production Goldman Sachs GS -0.10% analysts wrote in a research note.

Natural gas production in the U.S. has soared since 2005 as drilling companies began to use new technology to exploit the country’s vast reserves of shale gas.

The gas boom saw prices slump to their lowest in decades, even as oil prices soared to near record highs.

Not surprisingly, savvy drillers have been quick to shift gear and target areas richer in the more profitable commodity.

Goldman cites data compiled by Baker Hughes BHI -0.04% that shows the number of rigs drilling in the Haynesville shale gas formation in Louisiana and Texas have plummeted since the beginning of last year to less than 50 rigs from more than 150. Meanwhile, the number of rigs in the neighboring and liquids-rich Eagle Ford have soared in the same period from just under 100 to nearly 250.

Unlike in Haynesville, drillers in Eagle Ford can choose to drill for gas or oil. Given the current economics, many have chosen to focus on the oilier parts of the area, a move that Goldman estimates has meant gas production from the formation is currently half what it might be.

According to Goldman, moving a rig from the Haynesville to Eagle Ford cuts the gas production from the rig in half if it moves to an area of the formation that is rich in natural gas and by as much as 80% if it moves to a more oily area.

“Consequently, Eagle Ford natural gas production growth is not likely to be strong enough to compensate for declining production in Haynesville, and, on net, we expect the migration of rigs into Eagle Ford to slow US natural gas production,” says the bank.

To change this equation would require natural gas prices to recover to $5.30 a million British thermal units, Goldman says. With Henry Hub futures prices hovering around $2.80 a million British thermal units, we have a way to go yet.

original article

_

Motorists in Bradford County soon will have access to a natural gas filling station charging about $1.49 per gallon equivalent.

It’s one of several filling stations Chesapeake Energy plans to open in the Endless Mountains region to fuel its own natural gas-powered vehicles while opening the station to the public, said Norman Herrera, director of market development for Chesapeake Energy. The move is a hopeful bid to stimulate interest in natural gas-powered vehicles.

Several sessions at the Marcellus Shale Coalition Shale Gas Insight conference Friday in Philadelphia explored how to increase demand for natural gas. Use of natural gas as a transportation fuel would be a massive and badly needed new market, industry experts said. Near-record low natural gas prices have crimped margins for companies and changed patterns of natural gas development.

With few compressed natural gas filling stations, consumers are hesitant to invest in vehicles with a novel fuel source. While CNG technology has been around for decades, the chicken-egg problem – vehicles to justify the stations or stations to justify the vehicle purchase – prevents them from catching on. With natural gas inexpensive and abundant in the U.S., a gallon equivalent of CNG costs about $1.50 to $2 less per gallon than gasoline.

Pennsylvania has 11 CNG fueling stations, among the 519 in the nation, a number John Hanger, an environmental attorney and former secretary of the state Department of Environmental Protection, called “pathetic and dangerous.”

His former office overlooked a state flagpole, and Mr. Hanger remembered how often the flag was at half-staff, marking the death of a Pennsylvania soldier. In his mind, it was a death for oil, which should be unnecessary in the era of inexpensive, abundant natural gas. The natural gas that goes into vehicles, he said, displaces imported crude oil.

While consumers wait for filling stations, there may be another option. Owners of natural gas vehicles can fuel up their cars with the same gas that cooks their food and heats their water with home fueling stations.

“You pull into your garage at the end of the night, fill your tank and get full range in the morning,” said Todd Hartje, head of market requirements for fleet operations for Chrysler Corp.

Mr. Hartje called it an appliance that one day could be purchased at retail stores and hooked up as easily as a gas clothes dryer. The problem is that the home refueling stations are costly and can take an entire evening to refill.

Chrysler produces a Dodge Ram that runs on CNG. Honda produces a CNG-fueled Civic. Other automakers make conversion kits available to those who wish to turn a gasoline engine to natural gas. Mr. Hartje said Chrysler is working on CNG service vans and large sedans.

“This will work, and we think we are there,” he said.

CNG has a natural constituency among fleet operators who have been converting their vehicles. One temporary solution is making fleet filling stations open to the public.

Todd Campbell of Clean Energy, which operates CNG filling stations, said the level of awareness among the public and attention from the federal government make a broad-based adoption of the natural gas vehicle almost inevitable.

original article

_

BHP Billiton’s onshore U.S. shale plays will play an essential role in the company’s long-term strategy, despite the recent writedown of its Fayetteville shale assets due to weak North American natural gas prices.

U.S. natural gas prices would need to rise to $3.50/Mcf before BHP Billiton would reshift its drilling focus back towards dry natural gas, said J. Michael Yeager, the company’s group executive and chief executive of petroleum, at the Barclays CEO Energy Power Conference Tuesday in New York.

BHP Billiton has scaled back its Fayetteville and Haynesville drilling programs due to weak prices for dry natural gas, and has reallocated its rigs to liquids-rich plays such as the Eagle Ford and Permian plays in south and West Texas, Yeager told conference attendees.

Instead, the company is aggressively pursuing its Eagle Ford assets, with plans to spend over $1 billion over the next five years to expand Eagle Ford production infrastructure. This infrastructure includes six new processing plants, added capacity of 100,000 barrels per day of liquids and 1 billion cubic feet per day of gas and approximately 800 miles of pipeline, Yeager told conference attendees.

“The Eagle Ford is probably the most prolific field in the U.S., if not the world,” Yeager said.

With strong rates of return, with many wells exceeding 100 percent and average single well payback in one year, Yeager sees potential for higher recovery factors over time through reduced well spacing or improved technology.

BHP Billiton is also fully appraising its Permian acreage, which has had encouraging results so far. The company has increased its acreage from 378,000 acres at the time it acquired these assets to more than 440,000 acres. BHP Billiton plans to drill more than 60 wells in the Permian in fiscal year 2013, targeting oil from multiple pay horizons. The Wolfcamp shale is over 900 feet thick in some areas, Yeager noted.

The company will have approximately 40 rigs operating in the onshore U.S. in fiscal year (FY) 2013, with over 85 percent directed towards the liquids rich-Eagle Ford and Permian Basin, Yeager said.

While the company has shifted its focus to oil and liquids plays, it is prepared for a ramp-up in dry gas production as prices improve, noting that BHP Billiton’s dry gas shale properties are among the lowest costing plays in the United States. Yeager noted that the company remains optimistic about the long-term outlook for natural gas.

In the Haynesville, the company’s core acreage delivers “very strong” per well recoveries with some over 20 billion cubic feet (Bcf). The acreage has more than 20 percent forward rates of returns, even at current prices, and the company is adding significant value through continuous improvement initiatives, Yeager said.

BHP Billiton is focused on opportunity preservation and operational momentum in its Fayetteville operations. The company already is realizing significant operational improvements which will reduce costs and enhance value, Yeager said.

The company has approximately 1.6 million combined net acres across Texas, Louisiana and Arkansas, with a resource base of approximately 8 billion barrels of oil equivalent and four giant fields – Haynesville, Eagle Ford, Fayetteville, and the Permian – with 50-year lives, Yeager said.

BHP Billiton’s U.S. onshore assets offer strong returns and fast payback, as well as multiple upside opportunities and significant flexibility to respond to market conditions, Yeager said.

Shale liquids will represent the largest component of BHP Billiton’s $6.5 billion capital program planned for FY 2013. The company’s Gulf of Mexico and Western Australia activity will drive conventional spending in its capital program.

The company anticipates strong growth from its U.S. Gulf operations, where it anticipates future production growth from its Shenzi, Atlantis and Mad Dog fields, which are now online and producing. The company is planning to drill three significant wells in the Gulf in FY 2013.

Shenzi is still producing over 100,000 barrels of oil equivalent per day (boepd) after three years, with 94 percent average uptime during that period. The company achieved first water injection in May to increase reservoir performance, and has successfully appraised acreage north of Shenzi, said Yeager.

While the new offshore regulations in the Gulf following the Macondo incident have lengthened the drilling time per thousand feet from two to four days, BHP Billiton still has an advantage to the industry overall, Yeager noted.

The industry average drill time was five days before the Gulf drilling moratorium, and six days after the moratorium was lifted.

“We’re working through it like everyone else is,” said Yeager, noting of the changes in offshore drilling before and after Macondo.

Still, the company sees great potential in the Gulf, such as the Shenzi oil reservoir, which is taller than BHP Billiton’s 25-story office building.

The BP-operated Atlantis field is now online again after being down most of April, May and June, and the BP-operated Mad Dog is producing again after the drilling rig on top of the platform – which was blown off the top by Hurricane Ike in 2008 – has been replaced. The first new Atlantis producers are being drilled since the moratorium. Pre-commitment funding has also been approved for the Mad Dog phase 2 project, a new 130,000 boepd development that will double field deliverability, Yeager said.

The company is forecasting 8 percent production growth in the next fiscal year to 650,000 to 660,000 barrels of oil per day from its global operations, Yeager said. Fifteen percent of that production growth will be driven by liquids. Gas production will remain flat as production from the Macedon and North West Shelf in Australia offset lower shale dry gas volumes.

In the past five years, the company’s volumes have grown to over 600,000 boepd and underlying earnings before interest and taxes has grown to over $6 billion. The company’s workforce has also doubled to 4,000 employees.

BHP Billiton’s global asset base will offer plenty of training opportunities for its young workers, Yeager said.

BHP Billiton has proved reserves of over 2.5 billion barrels of oil equivalent and a total resource base of approximately 11 billion barrels of oil equivalent.

The company is expanding its production position offshore Western Australia, with:

continued development of the Pyrenees oil field

new volumes from Macedon

long term growth driven by the 10 trillion cubic feet Scarborough liquefied natural gas (LNG) development

additional growth potential from the Browse LNG project.

The company will drill one well offshore Western Australia in FY 2013 and has seismic activity planned in the region.

BHP Billiton will evaluate new plays offshore India with more than 3,106 miles (5,000 kilometers) of 2D seismic planned for fiscal year 2013. The company also will evaluate an extension to a key emerging play offshore South Africa, where it will conduct a 3,861- square mile (10,000 square kilometer) 3D seismic acquisition.

The company will also drill a well and gather over 3,728 miles (6,000 kilometers) of 2D seismic data offshore Malaysia in FY 2013.

original article

_

The coming U.S. energy boom, spearheaded by new technologies that have enabled us to recover vast amounts of previously inaccessible oil and natural gas from rock formations, will be important for several reasons, not least the nation’s competitive advantage in the global economy.

The United States has both huge deposits of natural gas and a huge head start on virtually everyone else in developing novel technologies that permit its recovery. Some countries may be able to catch up technologically, but that will likely take a decade. Others, such as Japan—where activists have blamed the Fukushima nuclear disaster on “fracking”—may never take advantage of the new technologies.

Our gain. Their loss.

Assuming the critics are wrong and that these untapped resources can be recovered with minimal environmental damage, this could be a game changer with a multiplier effect as America’s natural gas advantage enables U.S. utilities to convert abundant, low-cost gas into lower-cost electricity to power our factories.

Natural gas also has uses as an ingredient in producing fabrics, fertilizers, and plastics, among other things. Scientists at Honeywell (HON), for example, reportedly have developed a one-step process that turns natural gas into a plastics raw material.

Together, cheaper energy and lower-cost raw materials add up to lower-cost manufactured goods, ranging from agricultural chemicals to carpets and toys, which we can sell both domestically and overseas, creating U.S. jobs.

Currently, most domestic natural gas production, according to 2011 U.S. Energy Information Administration data,  comes from traditional energy producing areas: Texas (29%), Louisiana (13%), Wyoming (9%), the Gulf of Mexico (8%), and Oklahoma (8%). As fracking gains wider acceptance, other states will be able to join in the bounty, including Kentucky, New York, Ohio, Pennsylvania, Tennessee, and West Virginia.

Already, U.S. inventories of natural gas in storage are at all-time highs, reaching a record 3,852 billion cubic feet during the week ending Nov. 18, 2011.

At the cutting edge of the energy boom is North Dakota, which has produced more jobs than people to fill them—and more workers than places for them to live.

As the late natural resources economist Julian Simon pointed out three decades ago in response to doom-and-gloom predictions of life-threatening resource shortages, the key to society’s advancement and well-being has always been technological progress.

Just as many Americans had given up on the idea of energy independence, along comes this game-changer—a new technology that not only should allow us to become self-sufficient in meeting our energy needs, but will enable us to become a net energy exporter. Best of all, the cheap energy will give us a competitive advantage for the foreseeable future.

original article