Congressional Leaders Agree to Lift 40-Year Ban on Oil Exports

    Congressional Leaders Agree to Lift 40-Year Ban on Oil Exports

Dec 16, 2015 By Amy Harder And Lynn Cook

Accord is a key component to deal on tax, spending legislation
WASHINGTON—In a move considered unthinkable even a few months ago, congressional leaders have agreed to lift the nation’s 40-year-old ban on oil exports, a historic action that reflects political and economic shifts driven by a boom in U.S. oil drilling.
The measure allowing oil exports is at the center of a deal that Republican leaders announced late Tuesday on spending and tax legislation. However, Democrats haven’t confirmed the agreement. Both the House and Senate still must pass it and President Barack Obama must sign it into law.
The deal would lift the ban, a priority for Republicans and the oil industry, and at the same time adopt environmental and renewable measures that Democrats sought. These include extending wind and solar tax credits; reauthorizing for three years a conservation fund; and excluding any measures that block major Obama administration environmental regulations, according to a GOP aide.
By design or not, the agreement hands the oil industry a long-sought victory within days of a major international climate deal that is aimed at sharply reducing emissions from oil and other fuels, a deal opposed by the industry and one that will arguably require its cooperation.
More than a dozen independent oil companies, including Continental Resources CLR 2.29 % and ConocoPhillips , COP 2.08 % have been lobbying Congress to lift the ban on oil exports for nearly two years, arguing that unfettered oil exports would eliminate market distortions, stimulate the U.S. economy and boost national security.
A handful of Washington lawmakers representing oil-producing states, including Sens. Heidi Heitkamp (D., N.D.) and Lisa Murkowski (R., Alaska), have been working to convince once-wary politicians to back oil exports and allay worries that they will be blamed if gasoline prices were to rise.
Some U.S. refineries oppose oil exports, saying their business would be hit if crude oil is shipped overseas to be refined and warning that higher costs might be passed along to consumers. The U.S. government doesn’t limit exports of refined petroleum products, and those exports have more than doubled since 2007.
To address the refiners’ concerns, expressed most vocally by Democrats from the Northeast where several refineries are located, the spending bill changes an existing tax deduction for domestic manufacturing to benefit independent refineries in particular.
President Barack Obama had threatened to veto separate legislation lifting the export ban, but the White House isn’t expected to oppose the overall spending bill simply because it includes the measure, according to congressional aides.
Congress moved to ban oil exports under most circumstances following a 1973 Arab oil embargo that sent domestic gasoline prices skyrocketing.
With the increased use of fracking and other drilling technologies in recent years, U.S. oil production has shot up nearly 90% since August 2008, helping lower gasoline prices to levels not seen since 2009. Gas prices are less than $2 a gallon in many regions of the country, and the U.S. Energy Information Administration forecasts the price will average $2.04 this month and $2.36 next year.
It took this dramatic drop in oil prices, hovering below $40 a barrel, to catapult the policy change to the top of the Republican agenda. It helped prompt lawmakers of both parties to consider pairing renewable energy support with oil exports, a type of grand Washington deal-making that hasn’t been seen for years on the highly divisive issues of energy and environment.
The same low prices that generated momentum for lifting the ban could reduce its short-term economic impact, however, because the global market is saturated and U.S. oil companies have already slowed drilling in response.
John Hess, chief executive of Hess Corp., said low oil prices have increased the urgency for Congress to lift the ban, but he declined to say whether his company would immediately begin exporting oil if given the opportunity.
“It would be a function of market conditions,” Mr. Hess said in a recent interview. “But I think over time, definitely; If the market signals were there, we would have that option.”
The U.S. is already exporting nearly 400,000 barrels of crude a day to Canada, the biggest exemption under the ban. That is more than nine times as much as in 2008 but still just 3.8% of the U.S. oil produced every day.
A certain type of light oil is also already starting to flow overseas thanks to permission granted in 2014 by the Commerce Department, which allows producers to reclassify a certain type of oil as a refined fuel, similar to gasoline, which is legal to ship abroad.
The logistics of a new surge of oil exports would be relatively manageable, especially compared to exporting natural gas, which takes years of federal permitting and billions of dollars in technology to liquefy the gas.
Extensive networks of oil pipelines and storage tanks already stretch along the Gulf Coast from Corpus Christi, Texas, to St. James Parish, La. Those oil ports, where nearly a third of U.S. refineries are located, are for now geared toward unloading crude from tankers, not loading them. So initially there would be some constrained capacity that caps energy companies’ ability to ship crude out to foreign buyers.
But retrofitting those facilities—adding more deep-water dock space and equipment to load oil tankers—could happen quickly in a place like Texas, where permitting is easy and such projects face little community opposition. The ports of Corpus Christi and Houston are already undergoing dramatic expansions.
Several companies, including Enterprise Products Partners EPD 1.17 % LP, have already been ramping up their ability to export oil from Texas, and Enbridge Energy Partners EEP -0.55 % LP, based in Canada, plans to spend $5 billion to construct three new oil terminals between Houston and New Orleans.
—Kristina Peterson contributed to this article.

Tesla Planning Battery for Emerging Home Energy-Storage Market By Dana Hull and Mark Chediak – Feb 11, 2015, 10:48:18 PM

Tesla Planning Battery for Emerging Home Energy-Storage Market
By Dana Hull and Mark Chediak – Feb 11, 2015, 10:48:18 PM

(Bloomberg) — Tesla Motors Inc., best known for making the all-electric Model S sedan, is using its lithium-ion battery technology to position itself as a frontrunner in the emerging energy-storage market that supplements and may ultimately threaten the traditional electric grid.

“We are going to unveil the Tesla home battery, the consumer battery that would be for use in people’s houses or businesses fairly soon,” Chief Executive Officer Elon Musk said during an earnings conference call with analysts Wednesday.

Combining solar panels with large, efficient batteries could allow some homeowners to avoid buying electricity from utilities. Morgan Stanley said last year that Tesla’s energy-storage product could be “disruptive” in the U.S. and in Europe as customers seek to avoid utility fees by going “off-grid.” Musk said the product unveiling would occur within the next month or two.

“We have the design done, and it should start going into production in about six months or so,” Musk said. “It’s really great.”

Tesla already offers residential energy-storage units to select customers through SolarCity Corp., the solar-power company that lists Musk as its chairman and biggest shareholder. Tesla’s Fremont, California, factory is also making larger stationary storage systems for businesses and utility clients. The Palo Alto, California-based automaker has installed a storage unit at its Tejon Ranch Supercharger station off Interstate 5 in Southern California and has several other commercial installations in the field.

Utility Clients

But the even larger market may be utility clients.

“A lot of utilities are working in this space and we are talking to almost all of them,” Chief Technology Officer JB Straubel said on the earnings call Wednesday. “This is a business that is gaining an increasing amount of our attention.”

California sees energy storage as a critical tool to better manage the electric grid, integrate a growing amount of solar and wind power, and reduce greenhouse gas emissions. Utilities like PG&E Corp. are now required to procure about 1.3 gigawatts of energy storage by 2020, enough to supply roughly 1 million homes.

To contact the reporters on this story: Dana Hull in San Francisco at dhull12@bloomberg.net; Mark Chediak in San Francisco at mchediak@bloomberg.net

To contact the editors responsible for this story: Jamie Butters at jbutters@bloomberg.net Terje Langeland

Andy Hall & OPEC out of business. Time for a new way to Trade Oil.

How Oil Trading ‘God’ Hall Made Money as Crude Fell
By Bradley Olson – Dec 10, 2014, 6:18:09 AM

Andrew J. Hall, revered for anticipating major swings in the market, posted a 1 percent gain in his commodity hedge fund in November, according to people familiar with the matter. Photographer: Andrey Rudakov/Bloomberg
How does a renowned oil trader who bets on rising prices make money when crude plunges 18 percent in a month? By betting on the U.S. dollar at the same time.

Andrew J. Hall, revered for anticipating major swings in the market, posted a 1 percent gain in his commodity hedge fund in November, according to people familiar with the matter. Hall, who is leaving his longtime post as chief executive officer of Phibro LLC, the century-old commodities trading house now owned by Occidental Petroleum Corp. (OXY ▼ -3.29% 74.90), sees oil falling further as he focuses on his private fund.

“It’s a new era,” said Carl Larry, a former trader who is now a Houston-based director of oil and natural gas at Frost & Sullivan. “So many things have changed. This will be a chance for him to step back, assess the market, and maybe plot a comeback.”

The surprise rise at 64-year-old Hall’s Astenbeck Capital Management was driven by his bets on the greenback and a move to sell out of crude contracts before the worst of the rapid decline in prices, according to the people and his letters to investors in the $3 billion fund. A prolific art collector and Oxford University graduate, Hall is revered as a “god” by rival traders, according to “Oil,” a 2010 book by Tom Bower.

Known for his conviction that oil prices will rise in the long term and that U.S. shale drilling is overhyped, Hall still sees reasons for an oil rally — eventually. First he sees crude prices falling further to as low as $50 a barrel before recovering in the first half of next year, according to his Dec. 1 letter to investors.

Astenbeck, which posted losses in 2011 and 2013, is poised to finish the year up by as much as 7 percent, according to the people who asked not to be identified because the information isn’t public.

Phibro’s Fate

Andrew J. Hall, founder of Astenbeck Capital Management, right, and his daughter Emma Hall, stand for a photograph during the 21st annual Take Home a Nude gala and fundraiser for the New York Academy of Art at Sotheby’s in New York, U.S.. Photographer: Katya Kazakina/Bloomberg
The fate of Occidental’s Phibro has yet to be determined, with Hall’s departure making the future more uncertain. The oil company had already told employees this year that it planned to sell or close its energy trading unit by the end of 2014.

Phibro’s U.S. employees haven’t been active in trading for months and the overseas operations may be sold, the people said. Occidental announced plans in February 2014 to reduce exposure to proprietary trading, Melissa Schoeb, a company spokeswoman, said yesterday.

As CEO, Hall gained notoriety during the 2009 financial crisis for a nine-digit pay package while Phibro was owned by Citigroup Inc., igniting controversy over compensation at banks that had been kept afloat with federal funds.

‘Fool’s Errand’

The former trader for BP Plc anticipated oil’s rise to a record in 2008, and its subsequent fall, helping him land compensation near $100 million for three straight years. Before Phibro was bought by Occidental, it had been profitable every fiscal year since 1997 and in 80 percent of the quarters during that period. The trading house’s gains for those years amounted to $4.4 billion, according to data compiled by Bloomberg.

Saudi Arabia was correct not to cut production after last month’s meeting of the Organization of Petroleum Exporting Countries, Hall wrote to his investors on Dec. 1. The market is oversupplied, making any effort to sustain prices at $90 a barrel “a fool’s errand,” he said.

Too much has been invested in boosting output in recent years, particularly in U.S. shale formations where producers have drilled wells with cheap, borrowed money, he said. Hall has frequently said the oil boom is over-hyped and won’t last as long as the industry thinks. Low prices will run weaker shale operators out of business and lead to reduced spending on more costly developments such as those in Canada’s oil sands, deep-water drilling and Arctic projects, Hall said.

‘Reasonable Bet’

“As the oil industry and, more to the point, its investors and its lenders slam on the brakes and as low prices stimulate demand growth, the current glut will in time disappear — if not turn into a future shortage,” he wrote in his letter. “That at least is what the Saudis are counting on, and to us it appears a reasonable bet.”

Hall’s strategy in the past has often been to buy so-called long-dated oil contracts for delivery years into the future. He likes to invest when those futures are cheaper than current prices, because he believes oil will rise. Earlier this year, the futures contracts were selling for less than oil prices at the time.

In February, a futures contract for a barrel of December 2019 West Texas Intermediate benchmark crude was selling for $76 a barrel while current prices averaged $100. By July, those 2019 contracts were selling for $88. That represents a 16 percent gain. Astenbeck, which also invests in numerous other commodities, including precious metals, was up 19 percent through June, according to his investor letters.

Holding Off

In August and September, Hall told investors he’d cut risk and sold a number of oil contracts at the higher price, and planned to wait for the market to once again turn his way. Now, such futures contracts are selling above today’s WTI price of $62.53, an environment in which Hall in the past has held off investing, according to people familiar with his positions.

When prices fell, Hall invested in the dollar. Astenbeck’s 1 percent gain in November came as U.S. oil prices fell to the lowest level in five years. In that same period, the Bloomberg Dollar Spot Index, a gauge of the dollar’s strength against 10 major trading partners, rose 15 percent.

Hall’s departure from Phibro, where traders have cut their teeth for more than 40 years, and the potential for the unit’s closure rippled through trading circles yesterday, said Eric Rosenfeldt, a vice president at Virginia Beach, Virgina-based energy supply firm PAPCO Inc.

Phibro History

Among the most storied trading houses in history, Phibro helped create modern oil-trading markets, with more than 2,000 employees around the world at one time. In 1981, the firm was large enough to buy the investment bank Salomon Brothers. Founded in 1901 as Philipp Brothers trading metals and chemicals, Phibro dove into oil in 1973 when the Arab oil embargo caused prices to soar and left U.S. refineries searching for supplies.

Phibro’s original crude traders included Marc Rich, who would later gain infamy for breaking sanctions against Iran and fleeing the country to avoid federal indictments. Rich won a controversial pardon from President Bill Clinton. Thomas O’Malley, now the chairman of PBF Energy Inc., hired Hall for Phibro at a salary of $135,000, he told reporters last month.

“You expect to see some trading shops come and go in energy trading, but there are some staple firms like Phibro that have been around such a long time, and created so many good professionals throughout the industry,” Rosenfeldt said by phone. If its doors eventually close, “it would certainly be the end of a very long era.”

Solar and Wind Energy Start to Win on Price vs. Conventional Fuels NOVEMBER 23, 2014 AT 7:57 PM NYT > Business Day / By DIANE CARDWELL

For the solar and wind industries in the United States, it has been a long-held dream: to produce energy at a cost equal to conventional sources like coal and natural gas.

That day appears to be dawning.

The cost of providing electricity from wind and solar power plants has plummeted over the last five years, so much so that in some markets renewable generation is now cheaper than coal or natural gas.

Utility executives say the trend has accelerated this year, with several companies signing contracts, known as power purchase agreements, for solar or wind at prices below that of natural gas, especially in the Great Plains and Southwest, where wind and sunlight are abundant.

Those prices were made possible by generous subsidies that could soon diminish or expire, but recent analyses show that even without those subsidies, alternative energies can often compete with traditional sources.

In Texas, Austin Energy signed a deal this spring for 20 years of output from a solar farm at less than 5 cents a kilowatt-hour. In September, the Grand River Dam Authority in Oklahoma announced its approval of a new agreement to buy power from a new wind farm expected to be completed next year. Grand River estimated the deal would save its customers roughly $50 million from the project.

And, also in Oklahoma, American Electric Power ended up tripling the amount of wind power it had originally sought after seeing how low the bids came in last year.

“Wind was on sale — it was a Blue Light Special,” said Jay Godfrey, managing director of renewable energy for the company. He noted that Oklahoma, unlike many states, did not require utilities to buy power from renewable sources.

“We were doing it because it made sense for our ratepayers,” he said.

According to a study by the investment banking firm Lazard, the cost of utility-scale solar energy is as low as 5.6 cents a kilowatt-hour, and wind is as low as 1.4 cents. In comparison, natural gas comes at 6.1 cents a kilowatt-hour on the low end and coal at 6.6 cents. Without subsidies, the firm’s analysis shows, solar costs about 7.2 cents a kilowatt-hour at the low end, with wind at 3.7 cents.

“It is really quite notable, when compared to where we were just five years ago, to see the decline in the cost of these technologies,” said Jonathan Mir, a managing director at Lazard, which has been comparing the economics of power generation technologies since 2008.

Mr. Mir noted there were hidden costs that needed to be taken into account for both renewable energy and fossil fuels. Solar and wind farms, for example, produce power intermittently — when the sun is shining or the wind is blowing — and that requires utilities to have power available on call from other sources that can respond to fluctuations in demand. Alternately, conventional power sources produce pollution, like carbon emissions, which face increasing restrictions and costs.

But in a straight comparison of the costs of generating power, Mr. Mir said that the amount solar and wind developers needed to earn from each kilowatt-hour they sell from new projects was often “essentially competitive with what would otherwise be had from newly constructed conventional generation.”

Experts and executives caution that the low prices do not mean wind and solar farms can replace conventional power plants anytime soon.

“You can’t dispatch it when you want to,” said Khalil Shalabi, vice president for energy market operations and resource planning at Austin Energy, which is why the utility, like others, still sees value in combined-cycle gas plants, even though they may cost more. Nonetheless, he said, executives were surprised to see how far solar prices had fallen. “Renewables had two issues: One, they were too expensive, and they weren’t dispatchable. They’re not too expensive anymore.”

According to the Solar Energy Industries Association, the main trade group, the price of electricity sold to utilities under long-term contracts from large-scale solar projects has fallen by more than 70 percent since 2008, especially in the Southwest.

The average upfront price to install standard utility-scale projects dropped by more than a third since 2009, with higher levels of production.

The price drop extends to homeowners and small businesses as well; last year, the prices for residential and commercial projects fell by roughly 12 to 15 percent from the year before.

The wind industry largely tells the same story, with prices dropping by more than half in recent years. Emily Williams, manager of industry data and analytics at the American Wind Energy Association, a trade group, said that in 2013 utilities signed “a record number of power purchase agreements and what ended up being historically low prices.”

Especially in the interior region of the country, from North Dakota down to Texas, where wind energy is particularly robust, utilities were able to lock in long contracts at 2.1 cents a kilowatt-hour, on average, she said. That is down from prices closer to 5 cents five years ago.

“We’re finding that in certain regions with certain wind projects that these are competing or coming in below the cost of even existing generation sources,” she said.

Both industries have managed to bring down costs through a combination of new technologies and approaches to financing and operations. Still, the industries are not ready to give up on their government supports just yet.

Already, solar executives are looking to extend a 30 percent federal tax credit that is set to fall to 10 percent at the end of 2016. Wind professionals are seeking renewal of a production tax credit that Congress has allowed to lapse and then reinstated several times over the last few decades.

Senator Ron Wyden, the Oregon Democrat, who for now leads the Finance Committee, held a hearing in September over the issue, hoping to push a process to make the tax treatment of all energy forms more consistent.

“Congress has developed a familiar pattern of passing temporary extensions of those incentives, shaking hands and heading home,” he said at the hearing. “But short-term extensions cannot put renewables on the same footing as the other energy sources in America’s competitive marketplace.”

Where that effort will go now is anybody’s guess, though, with Republicans in control of both houses starting in January.

Brent Plunge To $60 If OPEC Fails To Cut, Junk Bond Rout, Default Cycle, “Profit Recession” To Follow

Brent Plunge To $60 If OPEC Fails To Cut, Junk Bond Rout, Default Cycle, “Profit Recession” To Follow

NOVEMBER 24, 2014 AT 8:01 AM
Zero Hedge / Tyler Durden

While OPEC has been mostly irrelevant in the past 5 years as a result of Saudi Arabia’s recurring cartel-busting moves, which have seen the oil exporter frequently align with the US instead of with its OPEC “peers”, and thanks to central banks flooding the market with liquidity helping crude prices remain high regardless of where actual global spot or future demand was, this Thanksgiving traders will be periodically resurfacing from a Tryptophan coma and refreshing their favorite headline news service for updates from Vienna, where a failure by OPEC to implement a significant output cut could send oil prices could plunging to $60 a barrel according to Reuters citing “market players” say.

By way of background, the key reason OPEC is struggling to remain relevant is because, as the FT reported over the weekend, “US imports of crude oil from Opec nations are at their lowest level in almost 30 years, underlining the impact of the shale revolution on global trade flows. The lower dependence on imports from the cartel, which pumps a third of the world’s crude, comes amid advances in hydraulic fracturing that has propelled domestic US production to about 9m barrels a day – the highest level since the mid-1980s.”

The US “shale miracle” is best seen on the following chart showing the total output of the US compared to perennial crude powerhouse, Saudi Arabia:

It is this shale threat that has become the dominant concern for OPEC, far beyond whatever current US national interest are vis-a-vis Ukraine, and Russia’s sovereign oil revenues, and as reported previously, Brent has to drop below to $75 or lower for US shale player to one by one start going offline.

Unfortunately, it may bee too little too late for the splintered cartel. As Bloomberg reports, “the days when OPEC members could all but guarantee consensus when deciding production levels for oil are long gone, according to a veteran of almost two decades of the group’s meetings.”

The global glut of crude, which has contributed to a 30 percent decline in prices since June 19, has left the Organization of Petroleum Exporting Countries disunited and dependent on non-members to shore up the market, said former Qatari Oil Minister Abdullah Bin Hamad Al Attiyah. The 12-member group is set to meet in Vienna on Nov. 27.

“OPEC can’t balance the market alone,” Al Attiyah, who participated in the group’s policy meetings from 1992 to 2011, said in a Nov. 19 phone interview. “This time, Russia, Norway and Mexico must all come to the table. OPEC can make a cut, but what will happen is that non-OPEC supply will continue to grow. Then what will the market do?”

“OPEC had been enjoying easy meetings, and decisions were taken without a sweat,” Al Attiyah said. “Now the situation is different.”

Oil markets are oversupplied by about 2 million barrels a day, and global economic growth is below expectations, he said. “The U.S., which was a major market for OPEC, is no longer welcoming imports. It’s now striving to become an oil exporter. It’s already exporting condensates.”

So if OPEC is unable to reach an agreement, what is the worst case? Back to Reuters, which says that “The market would question the credibility of OPEC and its influence on global oil markets if there was no cut,” said Daniel Bathe, of Lupus alpha Commodity Invest Fund.

That could send Brent down to around $60, Bathe said.

“Herding behavior and a shift to net negative speculative positions should accelerate the price plunge,” he added.

Fund managers are divided over whether OPEC will reach an agreement on cutting output. Bathe put the likelihood at no more than 50 percent.

The oil price has been falling since the summer due to abundant supply — partly from U.S. shale oil — and low demand growth, particularly in Europe and Asia.

As a result, some investors believe a small cut — of around 500,000 bpd — would not be enough to calm the markets.

If OPEC fails to agree a cut, prices will drop “further and quite quickly”, with U.S. crude possibly sliding to $60, he said. U.S. crude closed at $76.51 on Friday, with Brent just above $80.

It’s not all downside: there is a chance that OPEC will agree on a 1 million barrel or more cut, which would actually send prices higher:

“The market really wants to see that OPEC is still functioning … if there is a small cut, with an accompanying statement of coherence from OPEC that presents a united front, and talks about seeing demand recovery, and some moderation of supply growth, then Brent could move up to $80-$90.” “Prices below $80 are putting significant strain on the cartel’s weakest members such as Venezuela,” said Nicolas Robin, a commodities fund manager at Threadneedle. He said a bigger cut — of 1 million bpd or more — was an “outlier scenario”, but such a move would rapidly push prices above $85.

Then again, even thay may be insufficient if the market prices in an ongoing deterioration in global end-demand: “Doug King, chief investment officer of RCMA Capital, sees Brent falling to $70, even with a cut of 1 million bpd.”

So in a worst case scenario, where Brent does indeed tumble to $60, what happens? We already know the answer, as it was presented in “If WTI Drops To $60, It Will “Trigger A Broader HY Market Default Cycle”, Says Deutsche”:

… it is not just the shale companies that are starting to look impaired. According to a Deutsche Bank analysis looking at what the “tipping point” for highly levered companies is in “oil price terms”, things start to get really ugly should crude drop another $15 or so per barrell. Its conclusion: “we would expect to see 1/3rd of US energy Bs/CCCs to restructure, which would imply a 15% default rate for overall US HY energy, and a 2.5% contribution to the broad US HY default rate…. A shock of that magnitude could be sufficient to trigger a broader HY market default cycle, if materialized. ”

This explains why the HY space has been far less exuberant in recent weeks, and the correlation between HY and the S&P 500 has completely broken down.

Finally it is not just the junk bond sector that is poised for a rout should there be no meaningful supply cuts later this week: recall that in another note over the weekend, DB said that should crude prices take another leg lower, then the most likely next outcome is a Profit recession, which while left unsaid, will almost certainly assure a full-blown, economic one as well.

So keep an eye on Vienna this Thanksgiving: the black swan may just be coated with an layer of crude oil this year.

U.S. Oil Export Shift Prompts Fresh Look at Shipments

Condensate is a product and therefore can be exported. This is not a change in US Export Policy which prohibits Domestic Crude Exports.

By Zain Shauk and Dan Murtaugh Jun 26, 2014 12:53 AM ET Bloomberg

The U.S. could allow about 750,000 barrels a day of light crude oil to be exported, based on a new government stance defining what qualifies for overseas shipments.

Producers, refiners and pipeline companies are questioning exactly how much the Obama administration has relaxed its position on crude exports after the Commerce Department said June 24 it had categorized some lightly processed oil as exportable. The U.S. has prohibited most crude exports for four decades.

About 750,000 barrels a day of oil produced from U.S. shale plays is an ultra-light variety known as condensate, said Michael Wojciechowski, head of Americas downstream research for Wood Mackenzie Ltd. More than 70 percent of U.S. condensate comes from the Eagle Ford shale formation in Texas, where the majority of it goes through a heating process to burn off certain gases, Amrita Sen, chief oil economist for Energy Aspects Ltd. in London, said by phone.

The Commerce Department gave permission for condensates to be exported after going through the process, known as stabilizing, because then it can be considered a refined product. Though most raw crude oil exports are banned, refined products can be shipped abroad without limits.

Stabilizers at oil fields along the U.S. Gulf Coast may have a combined capacity of more than 200,000 barrels a day, according to Eric Lee, a commodities strategist for Citi Research.

August Exports?

“Processed condensate exports could begin as early as August,” Lee said in a research note. The U.S. could export 300,000 barrels of condensate per day by the end of the year, according to another Citi note.

Oil producers and refiners were unsure whether other types of crude might also qualify. Far more crude might be eligible for overseas shipments if any type of stabilized oil can qualify as a refined product, since the practice is widespread in the industry, said Charles Blanchard, an analyst for Bloomberg New Energy Finance.

West Texas Intermediate rose as much as 1.4 percent yesterday before paring gains to settle 0.4 percent higher at $106.50 a barrel. WTI for August delivery was up 19 cents at $106.69 on the New York Mercantile Exchange at 12:30 p.m. Singapore time today.

Oil producer BHP Billiton Ltd. said it welcomed the approval of condensate exports “under limited circumstances. BHP Billiton will consider marketing opportunities that may apply to our condensate production in the Eagle Ford and Permian Basin,” Jaryl Strong, a BHP spokesman, said in an emailed statement.

Additional Markets

As the industry figures out how to define the new rule, “that’ll really help companies on the downstream side better understand business opportunities and business impacts,” Dean Acosta, a spokesman for refiner Phillips 66 (PSX), said by phone.

Producers are keen to find additional markets for crude as output from U.S. shale formations has surged, causing bottlenecks in some regions. Refiners that have benefited from access to oil at prices below the international benchmark saw their shares drop yesterday after the Commerce Department change was announced.

The U.S. produced almost 8.4 million barrels a day in May and annual output is forecast to reach 9.3 million barrels a day in 2015, the highest since 1972, according to the Energy Information Administration.

Simple Equipment

More than 80 percent of the Eagle Ford’s output goes through stabilizers, Energy Aspects’ Sen said. Pioneer Natural Resources Co. (PXD), one of the companies that asked the government for permission to export stabilized condensate, said this week that a large portion of its 43,000 barrels a day of Eagle Ford production is condensate that already undergoes the processing.

Stabilizers are relatively simple pieces of oilfield equipment sometimes positioned near wellheads. They heat oil enough to boil off some gases, separating those products from the rest of the crude mix, Blanchard said.

“A caveman could do it,” Blanchard said, comparing the process to heating oil in an oven.

The process is commonly performed before putting oil and condensate into pipelines. Stabilizing oil is far less complex than the process of splitting or refining crude, which involve more sophisticated devices that heat and separate fuels from oil. Stabilizers that qualify crude for export can cost as little as one-tenth that of more complex processing units, said Wojciechowski at Wood Mackenzie.

To contact the reporters on this story: Zain Shauk in Houston at zshauk@bloomberg.net; Dan Murtaugh in Houston at dmurtaugh@bloomberg.net

To contact the editors responsible for this story: Susan Warren at susanwarren@bloomberg.net Pratish Narayanan

 

U.S. Gas Exports Unlikely to Ease Tensions Over Ukraine

U.S. Gas Exports Unlikely to Ease Tensions Over Ukraine

Europe Will Still Rely on Russian Gas as First U.S. Shipments Are Two Years Away

By

SELINA WILLIAMS
March 18, 2014 12:50 p.m. ET
LONDON—Natural gas exports from the U.S. are unlikely to help ease the tensions between Europe and Russia over Ukraine as the first such shipments are about two years away, a senior executive from oil and gas company BG Group PLC said Tuesday.

The U.S. has vast supplies of cheap natural gas thanks to the fracking boom and could become one of the world’s top three exporters of liquefied natural gas by 2025, BG said. Over the past week, some U.S. politicians have urged the Obama administration to speed up oil and natural gas exports to weaken Russia’s hand over Ukraine.

Russia supplies about 30% of Europe’s gas requirements, half of which transit via Ukraine, a factor some believe has stifled European opposition to Russia’s annexation of Crimea.

Federal law places heavy restrictions on U.S. companies from exporting natural gas to countries, like those in Europe, that aren’t among its free-trade partners.

Applications have already been made to export a total of over 260 million metric tons a year of LNG from the U.S. Even so BG, one of the biggest participants in the global LNG market, said it expects only about 60 million tons to 70 million tons of annual export capacity to be developed by 2025.

Andrew Walker, BG’s vice president of global LNG, said the company didn’t expect much fast-tracking of export applications unless there was a significant change in external circumstances.

BG clinched the first contract to export U.S. natural gas from the Sabine Pass, La., terminal in 2011. It expects those exports to commence in late 2015 or early 2016.

Mr. Walker said that the situation for gas prices and supplies in Europe was “fairly relaxed,” despite political tensions. The region only imported a net 35 million tons of LNG last year, the lowest level in nine years, with demand subdued due to weak economic growth, he said.

Meanwhile, global LNG supplies leveled off for a second consecutive year as new production was offset by unplanned outages, declines in output from existing plants and new projects ramping up more slowly than anticipated. This trend will keep LNG markets tight until at least the end of the decade, BG said in its annual global LNG outlook.

“We’re an industry in hiatus. Developing new supply, rather than demand is the principal challenge the industry faces,” Mr Walker said. Last year, only one in 10 new LNG projects awaiting final investment decisions was sanctioned.

Write to Selina Williams at selina.williams@wsj.com