BUSINESS Oil’s Fall Puts a Chill on U.S. Drilling Energy Firms Slash Spending, Staff as Crude’s Decline Accelerates

By LYNN COOK and ERIN AILWORTH WSJ
Dec. 10, 2014 7:15 p.m. ET

U.S. energy companies are starting to cut drilling, lay off workers and slash spending in the face of an accelerating decline in oil prices, which fell to a fresh five-year low Wednesday.

The number of rigs drilling for oil in North Dakota and parts of Texas has started to edge down, new drilling permits have dropped sharply since October, and many companies say they are going to focus on their most profitable wells.

EOG Resources Inc. this week said it would shed many of its Canadian oil and gas fields, close its Calgary office and lay off employees there as it refocuses in the U.S. Matador Resources Co. of Dallas is contemplating temporarily leaving the prolific Eagle Ford Shale area in South Texas in favor of drilling elsewhere in Texas and New Mexico where it can make more money.

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Investors sold off shares of energy companies including EOG as the U.S. benchmark oil price fell to $60.94 on Wednesday. EOG lost nearly 3% to $86.79 while shale specialists Continental Resources Inc. and Chesapeake Energy Corp. both declined about 7%. Many of these U.S. independent drillers have lost half their value since June.

Shares of global energy giants have fared better than the independent U.S. companies because their refining operations are benefiting from cheaper oil. But some of the biggest are disclosing cutbacks.

BP PLC, which has been cutting back since the Deepwater Horizon oil spill in 2010, outlined a further $1 billion restructuring on Wednesday. ConocoPhillips , one of the biggest shale producers in the U.S., recently said it would spend 20% less next year on drilling wells, honing in on its sweetest spots instead of drilling its more expensive areas like Colorado’s Niobrara.

“At this point a contraction is unavoidable,” said Karr Ingham, economist for the Texas Alliance of Energy Producers.

One reason for the stock declines is investors are skeptical: Whatever their plans, U.S. companies produced 9.1 million barrels a day last week, the highest level since 1983, according to federal data. There is so much oil sloshing around the U.S. that refiners can’t use it all, so 1.5 million barrels of crude went into U.S. oil stockpiles last week.

ENLARGE
Some companies will be able to keep pumping even at lower prices, depending on the location and quality of their wells. Enterprise Products Partners LP, which operates pipelines and oil storage terminals across the U.S., said its analysis shows that the average well in many shale formations aren’t profitable at $60 oil. But wells considered high grade can withstand much lower prices. For instance, some wells in South Texas are profitable at prices of $30 a barrel, while the best in North Dakota’s Bakken area can only withstand a drop to under $50 a barrel.

Energy companies’ hedging strategies run the gamut from Continental Resources, which cancelled nearly all its price hedges and projected oil prices would soon rise, to Pioneer Natural Resources Co. of Irving, Texas, which has hedged 85% of its oil and gas output for 2015. Companies that hedged their production aren’t as exposed to falling prices and may not have to pump less or curb spending as quickly.

Surging American oil output has helped create a global glut of oil that has sent prices spiraling downward. The benchmark U.S. oil price, which briefly rose above $107 a barrel in late June, closed below $61 a barrel Wednesday, down 43% since its summer high.

Drilling permits issued in the U.S. dropped 36% between October and November, according to data from Drillinginfo, but remain 13% above their year earlier level.

Another sign of the energy industry’s pullback: the number of rigs drilling for oil in the Eagle Ford Shale in Texas has started to drop. Drilling in the nation’s second most active oil region hit a peak of 210 rigs in July but recently fell to 190 rigs.

These declines don’t necessarily mean that U.S. oil output will fall, said Greg Haas, a director at research firm Stratas Advisors in Houston, because companies are getting more efficient at drilling. “It used to be if the rig count dropped then oil production dropped, but not anymore,” he said.

In a sense, energy companies are a victim of their own success. EOG, Chesapeake and others learned to drill and frack wells faster and wring more from each well. Chesapeake says its initial production at new wells in the Eagle Ford improved by 65% over the last five years.

Houston-based EOG took 22 days to drill a well in South Texas in 2011; today it takes less than nine days. The company recently said it can earn a 10% profit after taxes even if oil prices were to fall to $40 a barrel.

However, companies with a lot of debt, low rates of return and little chance of drilling their way to better profitability will be hurt if crude remains below $75 a barrel, according to analysts at Global Hunter Securities.

Among the companies they cited was Triangle Petroleum Corp. Jon Samuels, president of the Denver-based independent explorer, said his company is profitable at the current price of oil.

Triangle’s shares are down 47% in the last two months. It is pushing vendors for cheaper prices for drilling equipment and contract labor in the new year, which should help bring down costs, he said.

“You’re going to see activity levels and spending go down substantially compared to this year,” Mr. Samuels said, adding that the stock market reaction to crude’s price drop has been overblown.

Write to Lynn Cook at lynn.cook@wsj.com and Erin Ailworth at Erin.Ailworth@wsj.com

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.”

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.

Daniel Yergin: Why OPEC No Longer Calls the Shots

  • The Wall Street Journal
  • OPINION
  • October 14, 2013, 7:26 p.m. ET

Daniel Yergin: Why OPEC No Longer Calls the Shots

The oil embargo 40 years ago spurred an energy revolution. World production is 50% higher today than in 1973.

  • DANIEL YERGIN

Forty years ago, on Oct. 17, 1973, the world experienced its first “oil shock” as Arab exporters declared an embargo on shipments to Western countries. The OPEC embargo was prompted by America’s military support for Israel, which was repelling a coordinated surprise attack by Arab countries that had begun on Oct. 6, the sacred Jewish holiday of Yom Kippur.

With prices quadrupling in the next few months, the oil crisis set off an upheaval in global politics and the world economy. It also challenged America’s position in the world, polarized its politics at home and shook the country’s confidence.

Yet the crisis meant even more because it was the birth of the modern era of energy. Although the OPEC embargo seemed to provide proof that the world was running short of oil resources, the move by Arab exporters did the opposite: It provided massive incentive to develop new oil fields outside of the Middle East—what became known as “non-OPEC,” led by drilling in the North Sea and Alaska.

The Prudhoe Bay oil field was discovered in Alaska five years before the crisis. Yet opposition by environmentalists had prevented approval for a pipeline to bring the oil down from the North Slope—very much a “prequel” to the current battle over the Keystone XL pipeline. Only in the immediate aftermath of the embargo did a shaken Congress approve a pipeline that eventually added at its peak as much as two million barrels a day to the domestic supply.

image

image

© Corbis

A Connecticut filling station in 1974 amid the oil embargo.

The push to find alternatives to oil boosted nuclear power and coal as secure domestic sources of electric power. The 1973 crisis spawned the modern wind and solar industries, too. By 1975, 5,000 people were flooding into Washington, D.C., for a conference on solar energy, which had been until then only “a subject for eco-freaks,” as one writer noted at the time.

That same year, Congress passed the first Corporate Average Fuel Economy standards, which required auto makers to double fuel efficiency—from 13.5 miles per gallon to 27 miles per gallon—ultimately saving about two millions barrels of oil per day. (The standards were raised in 2012 to 54.5 miles per gallon by 2025). France launched a “war on energy waste,” and Japan, short of resources and fearing that its economic miracle was at risk, began a drive for energy efficiency. Despite enormous growth in the U.S. economy since 1973, oil consumption today is up less than 7%.

The crisis also set the stage for the emergence of new importers that have growing weight in the global oil market. In 1973, most oil was consumed in the developed economies of North America, Western Europe and Japan—two thirds as late as 2000. But now oil consumption is flat or falling in those economies, and virtually all growth in demand is in developing economies, now better known as “emerging markets.” They represent half of world oil consumption today, and their share will continue to increase. Exporting countries will increasingly reorient themselves to those markets. Last month, China overtook the U.S. as the world’s largest net importer of oil.

A lasting lesson of the crisis years is the power of markets and their ability to adjust to disruptions, if government allows them to. The iconic images of the 1970s—gas lines and angry motorists—are trotted out whenever some new disruption happens. Yet those gas lines weren’t the result of markets. They were the largely self-inflicted result of government interference in markets with price controls and supply allocation. Today, the oil market is much more transparent owing to the development of futures markets.

The 1970s were also years of natural-gas shortages, which turned into a bitter political issue, particularly within the Democratic Party. Many at the time attributed these shortages to geology, but they too were the result of regulation and price controls. What solved the shortages wasn’t more controls but their elimination, which resulted in an oversupply that became known as the “gas bubble.” Today, abundant natural gas is the default fuel for new electricity generation. The lesson is that markets and price signals can work very efficiently, and surprisingly swiftly, even in crises, if they are allowed to.

There will be future energy disruptions because there is still much political risk around oil. In 2013, the Middle East is still in turmoil, but the alignments are different. In 1973, Iran was one of America’s strongest allies in the Middle East. Tehran didn’t participate in the embargo and pushed oil into the market. But since the 1979 Islamic revolution, Washington and Tehran have been adversaries. Meanwhile, Saudi Arabia, which was at the center of the 1973 embargo, is now America’s strongest Arab ally.

The real lesson of the shock of 1973 and the second oil shock set off by the overthrow of Iran’s shah in 1979 is that they provided incentives—and imperatives—to develop new resources. Today, total world oil production is 50% greater than in 1973. Exploration in the North Sea and Alaska was only the beginning. In the early 1990s, offshore production expanded farther out into the Gulf of Mexico, opening up deep water as a new oil frontier. In the late 1990s, Canadian oil sands embarked on an era of growth that today makes them a larger source of oil than Libya before its 2011 civil war.

Most recent is the development of “tight oil,” the spinoff from shale gas, which has increased U.S. oil output by more than 50% since 2008. This boom in domestic output increases energy supply, and combined with shale gas has a much wider economic impact in jobs, investment and household income. As these tight-oil supplies increase, and as the U.S. auto fleet becomes more efficient, oil imports have declined. Imports reached 60% of domestic consumption in 2005, but they are now down to 35%—the same level as in 1973.

As the U.S. imports less oil it also produces more to the benefit of energy security. There are several million barrels of oil now missing from the world oil market, owing to sanctions on Iranian oil, disappointments in Iraqi production, and disruptions to varying degrees in Libya, South Sudan, Nigeria and Yemen. The shortfall is being partly made up by Saudi Arabia, which is producing at its highest level.

But the growth in U.S. oil output has been crucial in compensating for the missing barrels. Without it, the world would be looking at higher oil prices, there would be talk of a possible new oil crisis, and no doubt Americans would once again start seeing images of those gas lines and angry motorists from 1973.

Mr. Yergin, vice chairman of IHS, is the author of “The Quest: Energy, Security, and the Remaking of the Modern World” (Penguin Press, 2012).

A version of this article appeared October 15, 2013, on page A19 in the U.S. edition of The Wall Street Journal, with the headline: Why OPEC No Longer Calls the Shots.

Copyright 2012 Dow Jones & Company, Inc. All Rights Reserved

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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.

Oil-by-rail feeding East Coast Refineries Displacing Imported Crude

Oil-by-rail feeding PADD 1

Published: Sept. 19, 2013 at 7:27 AM

WASHINGTON, Sept. 19 (UPI) –WASHINGTON, Sept. 19 (UPI) — The increase in the amount of oil reaching refineries on the eastern U.S. coast is likely coming from rail deliveries, the U.S. energy department said.

Most of the crude oil reaching refineries in the Petroleum Administration for Defense District 1, which represents the East Coast market, is typically imported.

The Energy Information Administration, the Energy Department’s analytical division, said crude oil volumes at PADD 1 refineries increased steadily during spring and summer 2013. At the same time, there’s been a decline in net crude oil imports because of higher domestic production.

EIA said there’s a growing supply of crude oil delivered to PADD 1 that can’t be accounted for by production, imports or other forms of transport.

“Crude oil delivered via rail to East Coast refineries is likely contributing to the increase in unaccounted-for crude oil supply above historical levels,” the administration said in a report published Wednesday.

EIA in its short-term market report, published last week, said U.S. crude oil production in August averaged 7.6 million barrels per day, the highest monthly level since 1989.

The Association of American Railroads said last week petroleum and petroleum products were totaled 11,950 carloads, representing approximately 8.3 million barrels, for the week ending Sept. 7. That’s a 4.8 percent increase from the same time last year.

© 2013 United Press International, Inc. All Rights Reserved.

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Companies Unplug From the Electric Grid, Delivering a Jolt to Utilities

BUSINESSSeptember 17, 2013, 11:05 p.m. ET

Companies Unplug From the Electric Grid, Delivering a Jolt to Utilities

By REBECCA SMITH and CASSANDRA SWEET CONNECT

Michal Czerwonka for The Wall Street Journal

At Kroger’s food-distribution center in Compton, Calif., a tank system converts organic waste into biogas to produce electricity used by the facility

On a hill overlooking the Susquehanna River, two big wind turbines crank out electricity for Kroger Co.’s Turkey Hill Dairy in rural Lancaster County, Pa., allowing it to save 25% on its power bill for the past two years.

Across the country, at a big food-distribution center Kroger also owns in Compton, Calif., a tank system installed this year uses bacteria to convert 150 tons a day of damaged produce, bread and other organic waste into a biogas that is burned on site to produce 20% of the electricity the facility uses.

These two projects, plus the electric output of solar panels at four Kroger grocery stores, and some energy-conservation efforts are saving the Cincinnati-based grocery chain $160 million a year on electricity, said Denis George, its energy manager. That is a lot of money that isn’t going into the pockets of utilities.

From big-box retailers to high-tech manufacturers, more companies across the country are producing their own power. Since 2006, the number of electricity-generation units at commercial and industrial sites has more than quadrupled to roughly 40,000 from about 10,000, according to federal statistics.

Experts say the trend is gaining momentum, spurred by falling prices for solar panels and natural gas, as well as a fear that power outages caused by major storms will become more common.

Michal Czerwonka for The Wall Street Journal

Organic waste

“The battle cry is Hurricane Sandy,” said Rick Fioravanti, vice president of energy-storage technology at DNV Kema, a Netherlands-based consulting company.

The growing number of companies that are at least partly energy self-sufficient is sending a shudder through the utility industry, threatening its revenues and growth prospects, according to a report earlier this year by the Edison Electric Institute, a trade association for investor-owned electric companies.

State and federal regulators say they are worried that utilities could end up with fewer customers to pay for costly transmission lines and power plants.

Utility executives, meanwhile, are asking themselves a disquieting question: “Am I going to just sit here and take it and ultimately be a caretaker of a museum, or am I going to be part of that business” that’s emerging, said Nick Akins, chief executive of American Electric Power Co., a big Ohio-based utility. AEP is considering helping its customers install their own generating facilities.

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On-site generation still accounts for less than 5% of U.S. electricity production. But it is peeling off some of the bulk sales that utilities find especially profitable. And some of the companies getting into the business think it is approaching a tipping point called “grid parity,” at which point power would be as cheap to make as to buy from a utility.

Since 2007, when the first solar arrays went up on its store roofs in California, the installed costs of Wal-Mart Stores Inc.’s solar systems have dropped from $6 or $8 per watt of capacity to about $3.50 per watt, said David Ozment, the company’s senior director of energy management. He said he expects the retailer to be paying as little for solar power as utility power “in less than three years,” opening the floodgates to solar expansion.

Wal-Mart produces about 4% of the electricity it uses but intends to make 20% by 2020, taking advantage of idle acreage on thousands of store rooftops.

On-site generation isn’t a new idea. It existed before the electric grid—the interconnected system of power plants, substations and transmission lines that ferry power thousands of miles—was stitched together beginning in the 1920s.

But for most of the past 50 years, the practice was associated mostly with remote locations like Alaska fish canneries or industrial facilities like oil refineries that generated lots of waste heat that could be harnessed for power production.

Almost overnight, that niche market has gone decidedly mainstream. Six years ago, Google Inc. attracted attention by installing big solar arrays atop its Silicon Valley complex in California. Other tech companies followed suit, worried about ensuring power supplies for energy-hungry server farms and achieving sustainability objectives.

Apple Inc. now gets 16% of its electricity from solar panels and fuel cells that run on biogas. Apple’s data center in Maiden, N.C., makes all the power it consumes, a company spokeswoman said.

BMW AG’s assembly plant in South Carolina, which made 300,000 vehicles last year, gets half its electricity from an on-site energy center that burns methane piped to it from a nearby garbage dump. Drugstore chain Walgreen Co., which has solar panels at 155 stores, plans to install them at 200 more.

Falling equipment prices make on-site generation increasingly attractive. From 2002 to 2012, the cost of installed solar systems fell by half, according to an August report from the Lawrence Berkeley National Lab. Companies also have the option of leasing big solar systems, rather than incurring the capital cost of buying them.

Many “clean energy” projects also qualify for federal and state subsidies. In the case of solar installations, there is a 30% federal tax credit, which is set to drop to 10% in 2017. Government officials say a shift to greener energy resources is good since it reduces the output from coal-fueled power plants, which produce about 40% of the nation’s electricity and are the most polluting.

But analysts say the importance of subsidies has been waning, overshadowed by steep declines in the cost of power-generating equipment. For example, the cost of solar modules—the biggest single component in a rooftop solar system—has dropped about 80% in the past four years, to about 65 cents a watt from about $4 a watt, said Galen Barbose, a senior researcher at the lab.

Companies also are turning to wind turbines and technologies like fuel cells, batteries, small natural-gas turbines and reciprocating engines, which are natural-gas-fueled cousins of the auto’s internal combustion engine.

Engineering and technology company SAIC Inc. is installing enough generating capacity at a data center outside New York to meet the center’s core needs, with batteries for backup power. The system uses reciprocating engines burning natural gas, an option considered reliable in storms because gas pipelines are buried.

A report released by the White House in August estimated that power outages caused by bad weather cost the U.S. economy $18 billion to $52 billion a year in lost productivity from 2003 to 2012.

Demand for fuel cells in the U.S. is coming primarily from telecom companies, hotels and universities, said David Wright, CEO of ClearEdge Power Inc., a manufacturer in Hillsboro, Ore. Many buyers want reliable on-site generation as a hedge against storm-related outages.

By next year, Verizon Communications Inc. plans to install $100 million worth of fuel cells from ClearEdge and Bloom Energy, as well as solar panels, at 19 data centers and other facilities in seven states, including New York and New Jersey.

Some traditional utility companies are edging into the on-site generation business.

Edison International, which owns big utility Southern California Edison, recently bought a Chicago-based developer of rooftop solar projects, SoCore Energy LLC, and it is an investor in solar-finance company Clean Power Finance.

As power production becomes more decentralized, “I want to make sure the company is deeply involved,” said Edison CEO Ted Craver.

Write to Rebecca Smith at rebecca.smith@wsj.com and Cassandra Sweet at cassandra.sweet@dowjones.com

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