Oil in the age of coronavirus: a U.S. shale bust like no other

BUSINESS NEWS
APRIL 15, 2020 / 1:06 AM / UPDATED 7 HOURS AGO

Oil in the age of coronavirus: a U.S. shale bust like no other

Jennifer Hiller, Liz Hampton
7 MIN READ

HOUSTON/DENVER (Reuters) – Texas oilman Mike Shellman has kept his MCA Petroleum Corp going for four decades, drilling wells through booms and busts and always selling his crude to U.S. oil refiners.

FILE PHOTO: The sun is seen behind a crude oil pump jack in the Permian Basin in Loving County, Texas, U.S., November 22, 2019. REUTERS/Angus Mordant/File Photo

But now the second-generation oilman has abandoned drilling any new wells this year and postponed some maintenance amid a sharp drop in global oil prices and brimming storage tanks. He is considering shutting most of his production down, for the first time ever.

Oil fields from Texas and New Mexico to Oklahoma and North Dakota are going quiet as drilling halts and tens of thousands of oil workers lose their livelihood. Fuel demand has plunged by as much as 30 million barrels per day (bpd) – or 30% – as efforts to fight the coronavirus pandemic have grounded aircraft, reduced vehicle usage and pushed economies worldwide toward recession.

“What scares me is not even being able to sell the product,” the grizzled oil hand said from his firm’s San Marcos, Texas, headquarters.

Refiners and other buyers are warning they may refuse his oil once contracts expire this month, he said. Or they may offer to buy at a price below his costs, so he is preparing to dip into retirement savings to pay employees, he said.

The governments of global oil producers and consumers are seeking to make unprecedented cuts to overall supply of some 19.5 million bpd. U.S. President Donald Trump heralded the deal to cut supply as one that would save hundreds of thousands of U.S. jobs.

But oil prices fell again this week, dropping as much as 10% on Tuesday, because even those cuts may fail to stem the glut. Prices remain far below production costs for many U.S. producers, including those in the U.S. shale fields – the scene of a revolution in the energy industry over the past decade that made the United States the world’s top producer.

 

Across the United States, up to 240,000 oil-related jobs will be lost this year, about a third of the onshore and offshore oilfield workforce, estimates consultancy Rystad Energy.

The U.S. oil boom died on March 6, the day Saudi Arabia and Russia ended a four-year pact that curbed output and gave shale a price umbrella. Shale firms have accrued hefty debt during the years of expansion, leaving them exposed to the price crash that followed.

In March, U.S. oil futures tumbled to $20 a barrel, a third of the January price and less than half what many require to cover production costs. The March drop led dozens of shale producers to cut spending and several retained debt advisors.

“As soon as the virus hit and oil prices dropped, they sent everybody home,” said Joel Rodriguez, chief administrator of La Salle County, home of Texas’s second-most productive oilfield.

Shale oil producers face well closures and “industry wide financial distress” even after the OPEC cuts, said Artem Abramov, head of shale at consultancy Rystad Energy. In some fields, he expects regional prices will hit single-digits per barrel, he said. (For a graphic, click here)

Spending on oil field services will fall 21% to $211 billion this year, the lowest since 2005, according to researcher Spears & Associates.

 

Unlike the 2014-2016 oil bust, lenders are not making more financing available to producers, said Raoul Nowitz, head of restructuring at SOLIC Capital Advisors. He predicts up to 60 oil producers will seek protection from creditors this year, and many will not emerge under new owners. Some banks are setting up operations to take over and run failed producers.

LAYOFFS AND SHUT-INS

OPEC’s cuts may not be deep enough for oil producer Texland Petroleum, which operates 1,200 wells in the Permian Basin, the top U.S. oilfield. U.S. refiner and pipeline operator Phillips 66 asked President Jim Wilkes to reduce his deliveries by 15%, and another buyer canceled his contract outright.

“We’ve never had a time when we couldn’t sell the oil we produce. And that’s going to happen this time,” said Wilkes.

Average daily U.S. oil production this year will fall 500,000 bpd, to 11.8 million bpd and sink another 700,000 bpd next year, the Energy Information Administration estimated. (For a graphic, click: here)

Production cuts are too late for workers like Jeremy Davis, a 36-year-old who in March lost his business development job at Advanced BioCatalytics, which makes chemicals for hydraulic fracturing.

“They won’t be fracking many wells for the rest of the year,” said Davis, who after 16 years in the oilfield would now consider work outside the oil business. “I can’t wait around for the industry to come back,” he said.

Wall Street investors had already pulled back on the shale sector over the past couple of years because of poor returns, leaving producers with limited options for refinancing, said industry executives and analysts.

“There is no more lifeline,” said Lance Loeffler, the finance chief at top U.S. fracking service provider Halliburton Co.

PayZone Directional Services, a Denver-based driller, threw in the towel last month.

We could have stayed open and run until the money was gone but sometimes you just have to know when to cash in your chips and leave the table,” said Beth Thibodeaux, chief executive officer.

TIME TO MOVE ON

So much unsold oil is sloshing around that some pipeline operators, fearful of having their lines clogged, are insisting that producers halt connecting new wells and prove they have buyers or storage outlets before oil from existing wells can be put into a line.

They have warned “by mid-May storage is full” and will refuse to take any more, said Scott Sheffield, CEO at Permian Basin producer Pioneer Natural Resources.

He and some other executives in Texas and Oklahoma want state regulators to mandate up to 20% output cuts, sparing only the smallest producers. In Texas, energy regulators on Tuesday heard Sheffield call for a state order to halt 1 million bpd from its shale fields to prevent sale at below production cost.

 

MCA Petroleum owner Shellman said he tells friends who lost their jobs that it is time to leave the oil business. “It’s not ever going to be like it was.”

Shellman, who as a youngster got his first taste of the oil business accompanying his parents to their own oil wells, has promised to pay his employees from savings even if they have to shut in wells. But the pain goes well beyond Shellman’s wallet.

“From an emotional standpoint, this is killing me,” he said.

Reporting by Jennifer Hiller in Houston, Liz Hampton in Denver; editing by Gary McWilliams and Edward Tobin

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

Case For Exporting Marcellus Shale Gas

Q&A: Industry Economist Makes the Case for Exports

JUNE 18, 2013 | 3:26 PM
BY 

Liquefied natural gas (LNG) storage tanks and a membrane-type tanker are seen at Tokyo Electric Power Co.'s Futtsu Thermal Power Station in Futtsu, east of Tokyo February 20, 2013. Japan's imports of LNG hit a monthly record of 8.23 million tonnes in January, on an increased need for fuel to generate electricity after the nuclear sector was hit by the Fukushima crisis.

ISSEI KATO / REUTERS/LANDOV

Liquefied natural gas (LNG) storage tanks and a membrane-type tanker are seen at Tokyo Electric Power Co.’s Futtsu Thermal Power Station in Futtsu, east of Tokyo February 20, 2013. Japan’s imports of LNG hit a monthly record of 8.23 million tonnes in January, on an increased need for fuel to generate electricity after the nuclear sector was hit by the Fukushima crisis.

The nation’s new energy secretary Ernest Moniz spoke at an energy conference Monday, where he told the audience that applications for new natural gas export facilities would be decided upon by the end of the year. Gas producers want to sell their fuel overseas where it fetches a higher price. But before it gets shipped abroad, it has to be converted to its liquid form known as LNG – or liquefied natural gas. Building those facilities is expensive. The closest proposed LNG export terminal to the Marcellus Shale deposit is in Cove Point, Maryland. That could cost more than $3 billion dollars to convert from its former role as a natural gas import terminal. But domestic manufacturers and those who say U.S. security depends on keeping the fossil fuel stateside are pushing back. Environmentalists worry that exports will stimulate more production in states like Pennsylvania, where activists have been pushing to implement a drilling moratorium. StateImpact spoke to the chief economist of the American Petroleum Institute, John Felmy, about the future uses of natural gas, and the export issues.

A: Felmy: Well, Marcellus Shale could play a tremendous opportunity in terms of exports, because it’s such a vast deposit. Developing it can of course be used to supply other states, as we are doing now. But there is likely to be so much of it, that exporting it at a very good price would help in terms of keeping production going.

Q:  Phillips: Right now we have the price of natural gas at about $4 per million btu [British Thermal Units] here domestically. And what are we seeing oversees?

A: Felmy: Well in Europe, it’s about $12 per million BTU. But in Asia, it’s as much as $17 or $18 because of the challenges that Japan faces with the Fukushima plants.

Q: Phillips: And I know that the industry is getting a lot of push back from manufacturers who are concerned that if you start exporting natural gas the price for them is going to be too high. And what they have been saying the low price in natural gas has allowed them to come back to the US, and that they are seeing a manufacturing renaissance, because of natural gas prices being so low.

A: Felmy: I think there is enough to go around because all indications are, as the economists would say, is that the supply curve is really flat. In other words, when you have an increase in demand from exports you don’t kind of have a sharp increase in price. And if you look at the drilling data, you see that it tends to support that conclusion.

Q: Phillips: And why is that?

A: Felmy: It is because it is a huge resource, and the industry has been so creative at improving technology, such that we have gotten so much more gas from areas that we’ve never dreamed of. Where ten years ago we were talking about building all these LNG import terminals, and you had all these terminals built and so that was the consensus and everyone from Alan Greenspan on down.

Q: Phillips: The price of natural gas has gone up and down and up and down. And when you think about how much it costs to build an export facility, The Dominion proposal at Cove Point, Maryland is about $3.4 billion dollars, how do you manage that risk? It seems like a pretty risky thing.

A: Felmy: Lets let the market work. Lets not have government intervention. It’s the investors who are going to be taking the risk and things could change, but right now the U.S. is so far ahead of other countries, even though many other countries have huge deposits of shale gas, that we are going to have that opportunity for quite a while.

And so, if you look at the major competition internationally, right now it’s Australia and their costs have increased significantly. And if you look at the deposits in other areas like China, Argentina, and Russia they are large, but because of issues of rule of law, and ownership of the resource, because in most countries except for the United States, the government owns that gas. Here in the US private individuals can [own that gas]. Such factors are reasons why we are ahead and why we are likely to stay ahead.

Q: Phillips: So talk to me about the end user here, how feasible is it that we are going to be seeing cars run on natural gas?

A: Felmy: Well, only 3% of natural gas supply is being used in cars right now. It’s primarily fleets, busses, things like that. So you can expand the car fleet with natural gas, but it is very expensive.  So, it’s about $8,000 to convert car, at that level of expense the car will expire before you get your money back.

But for heavy duty trucks and fleets of cabs, that is a very viable option. We are also going to see a lot of growth in electric power generation. And because of emission restrictions we are already seeing a huge shift from coal to natural gas. We’re incidentally seeing a shift from nuclear to natural gas. For example, there’s a [nuclear] plant out in California, the San Onofre, they decided not to restart. Well, the only other alternative to supply that electricity is with natural gas.

Oil Trains Rumble Into Philly, Bringing Dakota Crude, Jobs And Safety Concerns

Oil Trains Rumble Into Philly, Bringing Dakota Crude, Jobs And Safety Concerns

SEPTEMBER 19, 2013 | 5:52 PM
BY 

CSX K040 Robert King

COURTESY OF ROBERT KING

Robert King remembers the very first time he saw an oil train.

“It was April 14, 2013.”

King, a 17-year-old Philadelphian, is a “railfan,” the name for members of a worldwide community of passionate, or some might say obsessive, train buffs.

On that day, King and railfans from the Midwest to the East Coast were busily tracking the inaugural run of a brand new train: the CSX K040, an oil train more than one-mile long hauling raw crude from the Bakken Shale in North Dakota bound for South Philadelphia.

With his camera bag slung over his shoulder, King pedaled his blue-and-white mountain bike to Schuylkill River Park in Center City and up the ramp to a foot bridge overlooking the CSX tracks. Then he settled in to wait. As he stood there, he recalls, “There’s some worry on my mind.”

King fretted that another train slated to use the tracks at the same time might ruin his dream photo. But he got lucky that day, snapping the photo of Philly’s first oil train that you can see on this page.

That’s because Philadelphia is at the center of a new industrial boom. Oil trains are becoming a common sight on tracks between North Dakota and Philadelphia. To get here, they travel through some densely populated areas – Chicago, Albany and New Jersey – which is raising some safety concerns.

Why? These shipments are coming on the same type of train that derailed in Lac-Mégantic, Quebec, last July, leaving 47 people dead and reducing the downtown to smoldering rubble.

Seen in another light, this rail traffic is very good news for America’s energy economy. Rail shipments are booming as fracking in the Bakken Shale continues to yield a glut of light, sweet crude oil.

More traffic, more accidents, more independence

Without enough pipelines to move it all underground, rail shipments have doubled since this time last year, according to the Energy Information Administration.

Fadel Gheit, a senior analyst with the investment bank Oppenheimer, has followed the oil and gas industry for more than 30 years. It  has been decades since Gheit has seen this kind of rail traffic.

“Two or three years ago, very seldom you heard that companies were using rail cars. Everybody now is,” he says. “Also the sheer number went from a few hundred rail cars to tens of thousands of rail cars. We have not, to my knowledge, expanded the rail line too much. We have not really spent a lot of money on infrastructure.”

Gheit wonders whether our rail lines can handle all this new activity and whether increasing traffic on the rails will lead to more accidents.

Pennsylvania’s governor, Tom Corbett, prefers to focus on the good news part of the equation. In his own way, the governor is also a rail fan.

Earlier this summer, Corbett paid a visit to ACF Industries – a rail car manufacturing plant in Milton, Northumberland County. The 114-year-old company closed in 2009. But the growing demand for rail tanker cars has pushed its doors wide open again.

“You are part of the piece of the puzzle of how we make this country energy independent of the Mid East,” Corbett told workers that day.

Bakken crude is also a direct cause for the revival of the 140-year-old Sunoco refinery in South Philadelphia. It was set to close when it got new life thanks to a joint venture between a private equity firm and a natural gas company.

In July, the refinery complex now known as Philadelphia Energy Solutions hit a milestone: ramping up shipments to five trains of Bakken crude a week.

July is also when the derailment in Lac-Mégantic happened.

A Quebec Provincial Policeman crosses the railway tracks inside the exclusion zone in the town of Lac Megantic, Quebec.  Hundreds of residents were evacuated from their homes when a runaway train loaded with crude oil exploded on July 6.

EPA/STEPHEN MORRISON /LANDOV

A Quebec Provincial Policeman crosses the railway tracks inside the exclusion zone in the town of Lac Megantic, Quebec. Hundreds of residents were evacuated from their homes when a runaway train loaded with crude oil exploded on July 6.

Learning from Lac-Mégantic

Inspectors have since concluded that the tankers on that derailed train were mislabeled. Samples from cars that didn’t ignite show the oil inside was actually more flammable than shipping documents reported.

Last week, Canadian transportation officials sent a letter to U.S. regulators warning them that emergency responders may not be getting the right information about these shipments.

But federal regulators have been asking questions about the safety of this boom in rail traffic even before the Lac-Mégantic derailment.

In March, the Federal Rail Administration started planning unannounced spot inspections of crude suppliers and transporters.

Nancy Kinner is director of the Coastal Response Research Center at the University of New Hampshire. She says rail has a fairly good safety record and most incidents are caused by human error “where humans override a system that is designed for protection or don’t believe the data that’s being given to them or simply make a bad judgment.”

Kinner says mislabeled shipments are a prime example of that.

Being prepared

The growing rail shipments pose challenges for local emergency planners trying to prevent accidents or ensure swift, safe clean up.

In Pennsylvania, the Public Utility Commission does spot inspections of tracks, rail cars and shipping documents to make sure transporters are complying with federal rules.

Emergency planning is left to counties.

Immediately after the accident in Canada, Philadelphia’s Office of Emergency Management told StateImpact Pennsylvania it does not get detailed information about rail shipments. Two months later, the agency won’t say whether or not it has gotten any new information or updated its emergency plans.

Federal law does not require railroads to share information about hazardous shipments with them, but Philadelphia Fire Commissioner Lloyd Ayers says CSX regularly communicates with his department about these shipments.

“It’s well before the shipment so we’ll know the chemical or the hazard that’s coming through,” Ayers says. “Where its destination is, where it originated from and what the quantities are so we can be prepared.”

A spokeswoman for the railroad told StateImpact that CSX shares information with local fire departments “upon request.” The railroad also holds training sessions with the Philadelphia fire department every year.

But CSX would not confirm what or even if it’s shipping to Philadelphia Energy Solutions.

The refinery denied a request for an interview about rail safety in the wake of the Canadian accident. But StateImpact did get an invitation to the grand opening of its permanent rail facility and an e-mail from a spokeswoman saying Philadelphia Energy Solutions “enthusiastically supports” safety inspections.

Meanwhile, Energy Solutions CEO Philip Rinaldi says the company is on the verge of becoming the single largest consumer of Bakken oil. Next month, it’ll be welcoming two trains a day, each carrying 70,000 gallons of crude.

Rail fans like Robert King will be out there watching it all unfold and capturing it on film.