Category Archives: Oil prices

Export of North American crude, Oil imports, Oil Industry, Oil prices

Nationwide trend: oil imports slowing down

Repost from Bloomberg Business Week

Oil Import Decline to U.S. Revealed by Louisiana as Truth

By Dan Murtaugh, Zain Shauk and Lynn Doan, Nov. 05, 2014
Oil
A four-decade ban on exporting most U.S. crude has stranded the bulk of America’s surging production within the nation’s borders, blocking inbound global shipments. Some cargoes permitted for export, such as those from Alaska, have begun moving overseas. South Korea last month received its first shipment of Alaskan oil in more than a decade. Photographer: Curtis Tate/MCT via Getty Images

Things are slowing down at the U.S.’s largest oil-import hub.

Just six years after importing more than 1 million barrels a day from countries including Saudi Arabia, Nigeria and Iraq, the Louisiana Offshore Oil Port is receiving just half of that from overseas, highlighting a nationwide trend at harbors from Mississippi to Pennsylvania. What’s more, with U.S. output soaring to a 31-year high, neighboring Texas has become the port’s second-biggest supplier.

“U.S. oil production has significantly changed the flows of oil around the world and LOOP is at the fulcrum,” Jamie Webster, head of global oil markets at IHS Inc., said by telephone from Washington Nov. 3. “We’re now essentially receiving nothing from Nigeria. This is a huge change. I’m an oil markets man and not an economist, but in general, this is a big stimulus” for the U.S.

Oil Prices

Booming oil and gas production created more than 159,000 jobs between 2007 and 2013, Bureau of Labor Statistics data show. The country will be self-sufficient in energy by 2030, BP Plc says.

A four-decade ban on exporting most U.S. crude has stranded the bulk of America’s surging production within the nation’s borders, blocking inbound global shipments. Some cargoes permitted for export, such as those from Alaska, have begun moving overseas. South Korea last month received its first shipment of Alaskan oil in more than a decade.

U.S. Consumers Benefit

Oil that the U.S. once imported now floods world markets, driving down prices 28 percent since June. That’s helped bring $3 gasoline back to U.S. pumps and provided what Citigroup Inc. describes as a $1.1 trillion boost to the global economy. Lower energy prices will translate into savings for Americans and will probably boost spending, said Amy Myers Jaffe, executive director of energy and sustainability at the University of California at Davis.

“It’s not just that people will have this benefit of lower gasoline prices, they’ll have this whole benefit of having a stronger U.S. economy and more jobs,” Myers Jaffe said.

Oil prices have maintained their decline as OPEC, the supplier of 40 percent of the world’s oil, resists pressure to curb production and help eliminate a global surplus. On Nov. 3, Saudi Arabian Oil Co. cut prices for all of its crude grades to the U.S., an e-mailed statement from the company showed.

WTI for December delivery rose $1.49 to settle at $78.68 a barrel on the New York Mercantile Exchange. Brent gained 13 cents to $82.95.

Lower Prices

A sustained stretch of low prices is unlikely to stop soaring output from major U.S. fields, with executives of oil companies including Continental Resources Inc. Chairman Harold Hamm and Occidental Petroleum Corp. Chief Executive Officer Stephen Chazen saying last month that production could be sustained even if prices fall lower.

“Oil prices are lower, but they’re not low enough to really put a big pinch on that activity,” said Ken Medlock, senior director of the Center for Energy Studies at Rice University’s Baker Institute in Houston. “You probably would need to see oil prices come off another $10 to $20 to see that fade.”

Horizontal drilling and hydraulic fracturing have drawn crude from previously inaccessible formations in Texas and North Dakota, propelling U.S. output to 8.97 million barrels a day, the highest level since 1983. Restrictions on exports have made U.S. oil cheaper than global crudes, so imports have fallen 31 percent since 2005 to 7.5 million barrels a day.

Supertanker Port

“Why is oil $80 instead of $95?” said David Hackett, president of Stillwater Associates LLC in Irvine, California. “All of a sudden all this oil is getting to the coast and pushing back world supplies.”

The shift is being felt 20 miles (32 kilometers) offshore in the Gulf of Mexico at the LOOP. Built in 1981, it’s the only U.S. port that can unload the world’s largest supertankers.

Shipments into the port peaked in 2005 at 1.18 million barrels a day, according to Louisiana state records. Imports have fallen to 510,000 barrels a day this year, and since May the port has received more oil from Texas than any country other than Saudi Arabia.

The U.S. Customs district in Morgan City, Louisiana, where the LOOP’s barrels are tallied, had 46 percent less petroleum import tonnage in September than the year before, according to Datamyne Inc.

Refining Profits

Morgan City has plenty of company. Philadelphia, home to the East Coast’s largest refining complex, had a 31 percent drop. Pascagoula, Mississippi, shipments declined 35 percent. Port Arthur, Texas, which brings in oil for some of the oldest refineries in the U.S., saw a 32 percent decline.

Returning to its roots, Exxon Mobil Corp. (XOM:US)’s Beaumont refinery is now processing more domestic crude. It imported 32,000 barrels of oil a day in July, down from around 220,000 in 2012. The refinery was built in 1903 by John D. Rockefeller’s Standard Oil Co. to process crude from the Spindletop gusher 4 miles away.

Third-quarter refining profit climbed to $1.02 billion from $592 million a year earlier, the Irving, Texas-based company reported (XOM:US) Oct. 31. That more than offset a $297 million decline in earnings from oil and gas production.

American refiners from Marathon Petroleum Corp. (MPC:US) to Phillips 66 have said in conference calls within the past week that they’re buying fewer expensive foreign crudes and more oil from the Bakken in North Dakota and Eagle Ford in Texas.

Domestic Crude

Instead of bringing in oil by ship, refiners have turned to pipelines and rail. Phillips 66 used 3,200 rail cars to get more of its crude from U.S. sources.

The company said 95 percent of its oil in the third quarter was either domestic or heavy oil priced below benchmarks. Phillips 66 will add 500 rail cars to its fleet by early next year, and expects to use only the less expensive crudes by the end of 2015, CEO Greg Garland said on an Oct. 29 conference call.

Back at LOOP, Terry Coleman, the port’s vice president for business development, said equipment has been reconfigured to accommodate smaller tankers and the shift in flows. On top of tanker unloadings and receipts from offshore drilling platforms, the company is now linked to an onshore pipeline operated by Royal Dutch Shell Plc, he said by phone yesterday.

“Given its size and its historical importance, LOOP is really the bellwether of the structural change that has taken place,” Darryl Anderson, managing director of Wave Point Consulting in Victoria, Canada, said by phone Nov. 3. “What it’s telling us is that there has been a fundamental change in U.S. energy sources.”

Bakken Shale, Oil Industry, Oil prices, Tar sands crude

Wall Street Journal: Big Oil Feels the Need to Get Smaller

Repost from The Wall Street Journal

Big Oil Feels the Need to Get Smaller

Exxon, Shell, Chevron Pare Back as Rising Production Costs Squeeze Earnings
By Daniel Gilbert and Justin Scheck, Nov. 2, 2014
Shell_Ft.McMurrayAlberta_Bbrg500
Extracting oil from Western Canada’s oil sands, such as at this Shell facility near Fort McMurray, Alberta, is a particularly expensive proposition. Bloomberg News

As crude prices tumble, big oil companies are confronting what once would have been heresy: They need to shrink.

Even before U.S. oil prices began their summer drop toward $80 a barrel, the three biggest Western oil companies had lower profit margins than a decade ago, when they sold oil and gas for half the price, according to a Wall Street Journal analysis.

Despite collectively earning $18.9 billion in the third quarter, the three companies— Exxon Mobil Corp. , Royal Dutch Shell PLC and Chevron Corp. —are now shelving expansion plans and shedding operations with particularly tight profit margins.

The reason for the shift lies in the rising cost of extracting oil and gas. Exxon, Chevron, Shell, as well as BP PLC, each make less money tapping fuels than they did 10 years ago. Combined, the four companies averaged a 26% profit margin on their oil and gas sales in the past 12 months, compared with 35% a decade ago, according to the analysis.

Shell last week reported that its oil-and-gas production was lower than it was a decade ago and warned it is likely to keep falling for the next two years. Exxon’s output sank to a five-year low after the company disposed of less-profitable barrels in the Middle East. U.S.-based Chevron, for which production has been flat for the past year, is delaying major investments because of cost concerns.

BP has pared back the most sharply, selling $40 billion in assets since 2010, largely to pay for legal and cleanup costs stemming from the Deepwater Horizon oil spill in the Gulf of Mexico that year.

SqueezePlaysWSJ.500

To be sure, the companies, at least eventually, aim to pump more oil and gas. Exxon and Chevron last week reaffirmed plans to boost output by 2017.

“If we went back a decade ago, the thought of curtailing spending because crude was $80 a barrel would blow people’s minds,” said Dan Pickering, co-president of investment bank Tudor, Pickering, Holt & Co. “The inherent profitability of the business has come down.”

It isn’t only major oil companies that are pulling back. Oil companies world-wide have canceled or delayed more than $200 billion in projects since the start of last year, according to an estimate by research firm Sanford C. Bernstein.

In the past, the priority for big oil companies was to find and develop new oil and gas fields as fast as possible, partly to replace exhausted reserves and partly to show investors that the companies still could grow.

But the companies’ sheer size has meant that only huge, complex—and expensive—projects are big enough to make a difference to the companies’ reserves and revenues.

As a result, Exxon, Shell and Chevron have chased large energy deposits from the oil sands of Western Canada to the frigid Central Asian steppes. They also are drilling to greater depths in the Gulf of Mexico and building plants to liquefy natural gas on a remote Australian island. The three companies shelled out a combined $500 billion between 2009 and last year. They also spend three times more per barrel than smaller rivals that focus on U.S. shale, which is easier to extract.

The production from some of the largest endeavors has yet to materialize. While investment on projects to tap oil and gas rose by 80% from 2007 to 2013 for the six biggest oil companies, according to JBC Energy Markets, their collective oil and gas output fell 6.5%.

Several major ventures are scheduled to begin operations within a year, however, which some analysts have said could improve cash flow and earnings.

For decades, the oil industry relied on what Shell Chief Financial Officer Simon Henry calls its “colonial past” to gain access to low-cost, high-volume oil reserves in places such as the Middle East. In the 1970s, though, governments began driving harder bargains with companies.

Oil companies still kept trying to produce more oil, however. In the late 1990s, “it would have been unacceptable to say the production will go down,” Mr. Henry said.

Oil companies were trying to appease investors by promising to boost production and cut investment.

“We promised everything,” Mr. Henry said. Now, “those chickens did come home to roost.”

Shell has “about a third of our balance sheet in these assets making a return of 0%,” Shell Chief Executive Ben van Beurden said in a recent interview. Shell projects should have a profit margin of at least 10%, he said. “If that means a significantly smaller business, then I’m prepared to do that.”

Shell late last year canceled a $20 billion project to convert natural gas to diesel in Louisiana and this year halted a Saudi gas project where the company had spent millions of dollars.

The Anglo-Dutch company also has dialed back on shale drilling in the U.S. and Canada and abandoned its production targets.

U.S.-based Exxon earlier this year allowed a license to expire in Abu Dhabi, where the company had pumped oil for 75 years, and sold a stake in an oil field in southern Iraq because they didn’t offer sufficiently high returns.

Exxon is investing “not for the sake of growing volume but for the sake of capturing value,” Jeff Woodbury, the head of investor relations, said Friday.

Even Chevron, which said it planned to increase output by 2017, has lowered its projections. The company has postponed plans to develop a large gas field in the U.K. to help bring down costs. The company also recently delayed an offshore drilling project in Indonesia.

The re-evaluation has also come because the companies have been spending more than the cash they bring in. In nine of the past 10 quarters, Exxon, for example, has spent more on dividends, share buybacks and capital and exploration costs than it has generated from operations and by selling assets.

Though refining operations have cushioned the blow of lower oil prices, the companies indicated that they might take on more debt if crude gets even cheaper. U.S. crude closed Friday at $80.54 a barrel.

Chevron finance chief Patricia Yarrington said the company planned to move forward with its marquee projects and is willing to draw on its $14.2 billion in cash to pay dividends and repurchase shares.

“We are not bothered in a temporary sense,” she said. “We obviously can’t do that for a long period of time.”

Bakken Crude, California oil industry, Crude By Rail, Fracking, Oil prices

Wall Street Journal analyzes California fracking and crude-by-rail, discusses Valero Benicia plan, others

Repost from The Wall Street Journal
[Editor:  Following the money…  WSJ’s important analysis of refinery trends in California includes a brief discussion of current and proposed projects, including Valero Benicia, with quotes by Valero spokesperson Bill Day and Andrés Soto on behalf of Benicians For a Safe and Healthy Community.  Significant quote: “Opposition over safety has drawn out the permitting process in some cases, making some companies rethink their strategies. Valero Energy Corp. in March canceled plans to build an oil-train terminal near its Los Angeles refinery. But Valero still hopes to add a terminal to the company’s Benicia, Calif., plant, 35 miles northeast of San Francisco.   ¶“Every day that goes by that we’re not able to bring in lower cost North American oil, is another day that the Benicia refinery suffers competitively,” says spokesman Bill Day. The state last month asked Benicia for another safety review to better forecast the potential for derailments and other accidents.” – RS]

California Finally to Reap Fracking’s Riches

Crude-by-Rail From Bakken Shale Is Poised to Reverse State Refiners’ Rising Imports
By Alison Sider and Cassandra Sweet, Oct. 7, 2014
Tanker cars line up in Bakersfield, Calif., where Alon USA Energy recently received permission to build the state’s biggest oil-train terminal. The Bakersfield Californian/Associated Press

For the past decade, the U.S. shale boom has mostly passed by California, forcing oil refiners in the state to import expensive crude.

Now that’s changing as energy companies overcome opposition to forge ahead with rail depots that will get oil from North Dakota’s Bakken Shale.

Thanks in large measure to hydraulic fracturing, the U.S. has reduced oil imports from countries such as Iraq and Russia by 30% over the last decade. Yet in California, imports have shot up by a third to account for more than half the state’s oil supply.

“California refineries arguably have the most expensive crude slate in North America,” says David Hackett, president of energy consulting firm Stillwater Associates.

Part of the problem is that no major oil pipelines run across the Rocky Mountains connecting the state to fracking wells in the rest of the country. And building pipelines is a lengthy, expensive process.

Railroads are transporting a rising tide of low-price shale oil from North Dakota and elsewhere to the East and Gulf coasts, helping to keep a lid on prices for gasoline and other refined products.

Yet while California has enough track to carry in crude, the state doesn’t have enough terminals to unload the oil from tanker cars and transfer it to refineries on site or by pipeline or truck.

Just 500,000 barrels of oil a month, or 1% of California’s supply, moves by rail to the state today. New oil-train terminals by 2016 could draw that much in a day, if company proposals are successful.

Bakken oil since April has been about $15 a barrel cheaper than crude from Alaska and abroad, according to commodities-pricing service Platts. That would cover the $12 a barrel that it costs to ship North Dakota crude to California by rail, according to research firm Argus.

The state’s lengthy permitting process has contributed to the shortage of oil-train terminals. Some California lawmakers also want to impose fees on oil trains to pay for firefighting equipment and training to deal with derailments and explosions. And community and environmental activists have been waging war on oil trains. The dangers of carrying hazardous materials by rail were underscored Tuesday when a train carrying petroleum derailed in Canada.

But energy companies recently won two hard-fought victories that will pave the way for California to get more crude by rail.

Kern County officials last month gave Alon USA Energy Inc. permission to build the state’s biggest oil-train terminal. That project, which the company hopes to finish next year, is designed to receive 150,000 barrels of oil a day in Bakersfield, Calif., 110 miles north of Los Angeles.

The site was home to an asphalt refinery until 2012 when Alon shut it down because it struggled to turn a profit. Alon plans to reconfigure and restart the plant, but much of the oil transported there by train will move by pipeline to other companies’ refineries in California.

Plains All American Pipeline LP says it plans to open a 70,000-barrel-a-day oil-train terminal in Bakersfield this month.

And in northern California, a judge last month dismissed a lawsuit brought by environmental groups that challenged Kinder Morgan Inc.’s rail permits. The company is now receiving oil trains at a Richmond, Calif., terminal near San Francisco that was built to handle ethanol.

Opposition over safety has drawn out the permitting process in some cases, making some companies rethink their strategies. Valero Energy Corp. in March canceled plans to build an oil-train terminal near its Los Angeles refinery. But Valero still hopes to add a terminal to the company’s Benicia, Calif., plant, 35 miles northeast of San Francisco.

“Every day that goes by that we’re not able to bring in lower cost North American oil, is another day that the Benicia refinery suffers competitively,” says spokesman Bill Day. The state last month asked Benicia for another safety review to better forecast the potential for derailments and other accidents.

Several oil-train explosions in the last 15 months—including last year’s blast in Lac-Mégantic, Quebec, that killed 47 people—have struck fear in many residents along rail corridors.

“These railcars are not safe at any speed,” says Andrés Soto, a musician from Benicia who has helped organize campaigns against several oil-train projects. “We don’t see that there’s any way that they can actually make these projects fail-safe.”

Environmental-impact challenges have been one means that groups have used to delay oil trains.

Pittsburg, Calif., officials say WesPac Midstream LLC’s proposed oil-train terminal is on hold after the state attorney general asked for an expanded environmental review. The company is gathering answers for regulators and hopes to gain approval and start accepting oil trains at the site by late 2016, 40 miles east of San Francisco, a WesPac spokesman says.

Even if oil trains are kept off California tracks, more fracked crude still could flow to California. A 360,000-barrel-a-day oil-train terminal in Vancouver, Wash., aims to transfer North Dakota crude from tanker cars to barges that will sail the Columbia River about 100 miles northwest to the Pacific Ocean. From there, it is a quick trip down the coast to California ports.

That project also has faced stiff headwinds. Refiner Tesoro Corp. and transportation provider Savage Cos. were forced to postpone the start for the Vancouver terminal because of approval delays. While the governor hasn’t approved the project, the companies say they expect to be up and running next year.

Bakken Crude, Crude By Rail, DOT-111, Oil prices, Tar sands crude, Volatile gases

LOCAL OP-ED – Jerome Page: The triumph of human ingenuity

Repost from The Benicia Herald

Jerome Page: The triumph of human ingenuity

August 8, 2014 by Jerome Page

TIME TO TAKE A CLOSE LOOK AT OUR STARTLING SUCCESS in solving our energy problems with oil — good old American Bakken crude along with a hefty swash of that Canadian tar sands crude. Canada being a very friendly neighbor, this seems a great deal on both sides of the border. And thanks to a fine railroad system, it’s just a simple straight shot from North Dakota and Alberta right up to our door here in Benicia, California! Providence be blessed!

And yet there are, as always, folks who not only want to examine that gift horse’s teeth but can be just plain ungracious — if not downright surly and disagreeable — about it. What could possibly be wrong with cheaper oil in copious quantities, without ever having to deal with folks who don’t even speak English?

But enough. I’ll step out of the Joe Schmoe character and comment just a bit on that question of what can, in fact, possibly be wrong.

From an Earth Island Journal clipping (June 29, 2014), a piece by Adam Federman, we read: “Since the Lac-Mégantic disaster (with its 47 dead) there has been a string of oil train collisions and derailments. Late on the night of November 7, a train carrying at least 2.7 million gallons of Bakken crude derailed near Aliceville, Alabama, resulting in dramatic explosions similar to those seen in Lac-Mégantic. Because the train exploded a few miles outside of Aliceville, no one was injured or killed. On December 30, a train carrying crude collided with another train outside of Casselton, North Dakota, releasing more than 400,000 gallons of oil into the surrounding land. At least half the town’s 2,400 residents were evacuated, though no one was injured. And on April 30, an oil train operated by CSX derailed in the city of Lynchburg, Virginia, sending flames and oil into the James River and forcing the evacuation of more than 300 residents. Last year more oil spilled in rail accidents — 1.15 million gallons — than the previous 35 years combined.” (Italics mine)

Then the following:

“Extra-flammable Bakken crude riskier to ship by rail than other oil, U.S. safety watchdog warns,” by Jeff Lewis, Jan. 2, 2014:

“CALGARY — U.S. authorities said Thursday crude oil shipped by rail from the Bakken shale in North Dakota across the United States and Canada ‘may be more flammable’ than other types of oil, as the latest in a string of explosive accidents focuses attention on the booming oil-by-rail trade.”

How about we ditch that “may be”! For example, another read on Casselton:

“‘There was a huge fireball’: Train carrying crude oil explodes after derailing in North Dakota,” by Dave Kolpack, Associated Press, Dec. 30, 2013:

“A train carrying crude oil from North Dakota’s oil patch derailed Monday near the small town of Casselton, setting off a series of fiery explosions. No injuries were initially reported, but officials were warning residents to stay indoors as the situation unfolded. Cass County Sheriff’s Sgt. Tara Morris says as many as 300 residents of Casselton may be evacuated.

“Morris estimates about 10 cars from a mile-long train caught fire and will have to burn out. She said it could take up to 12 hours before authorities can get close.

Next, “How crude-by-rail accidents may impact the U.S. oil market,” Reuters, Jan. 23, 2014:

“A spate of high-profile crude-by-rail accidents is making oil analysts consider how tighter rail safety standards could impact U.S. oil markets, by potentially crimping a mode of transport that has grown exponentially amid the shale drilling boom.

“Any regulation or industry-driven move to hastily sideline a fleet of some 75,000 older tank cars commonly used for shipping crude could roil U.S. oil logistics, boost costs for refiners, and even hit output from North Dakota’s giant Bakken field, oil analysts said.

“The scenario that many view as more likely — where older rail cars could be gradually retrofitted or retired — would be less disruptive but still raise transportation costs.” (And, of course, forestall greater dangers, but what the hell, what’s life without a little spice!)

“Tank cars known as DOT-111s are used to transport most of the 10 percent of U.S. oil production, or around 800,000 barrels per day, that is shipped by railroad. The cargoes have surged over the past half decade, offering drillers in fast-growing shale plays like the Bakken a quick and flexible way to send barrels to consumer markets without relying on limited regional pipelines.

“DOT-111 rail cars built before 2011, which have been involved in several accidents, are under scrutiny for safety issues that make them more likely to puncture in a derailment.

“Over the weekend, a train carrying North Dakota crude derailed in Philadelphia, although there was no fire or injuries.

“‘I view this as a potentially hugely significant rail risk,’ said Credit Suisse’s Jan Stuart, referring to how new crude-by-rail safety measures could impact Bakken-region oil logistics or production.” (That risk of course is financial, and when you’re talking financial risk, man you have an audience; human risk, risk to life and limb — not so much!)

“So far, the Department of Transportation has set a schedule for next year to draft new regulations, including updated tank car specifications, but it is facing pressure to move faster.

“‘Regulators have endorsed the new safety standards for newly built cars, but so far have not required any retrofitting,’ said Sandy Fielden of the RBN Energy consultancy in Austin. ‘If the existing fleet of older cars were to need retrofitting, it would be very disruptive.’”

And why in hell would we be wanting to do anything “disruptive” when the money is rolling in so beautifully! Is it that hard for people to focus on the crucial bottom line?!

“In the fast-growing Bakken, where pipeline capacity has not kept up with oil production, more than 70 percent of output that is approaching 1 million barrels per day now moves by rail, according to the North Dakota Pipeline Authority.

“Over half of the U.S. crude moved by rail hails from the Bakken, where the trend has allowed drillers to quickly send their barrels to refineries in the biggest fuel markets along U.S. coasts where they fetch higher prices, boosting profits.

“‘The most likely scenario is for regulators to gradually phase in safety improvements,’ said energy analyst Michael Wittner of Societe Generale. ‘That could increase transportation costs, but if there were a decision to replace older tank cars on short deadline, crude would be piling up in North Dakota.’” (Let’s not be disrupting the flow of oil — and cash.)

“Retrofitting the entire fleet of older DOT-111s would be costly and take up to ten years, the Rail Supply Institute, which represents tank car owners, said last year, in part because manufacturers are already struggling with a backlog of tank car orders. Newer DOT-111s feature safety improvements, but comprise only around 14,000 cars so far, according to the AAR.

“Sidelining older DOT-111s could depress Bakken oil prices at the wellhead as producers compete for insufficient pipeline capacity, eventually hurting production, Fielden said. Any fall in deliveries by rail could force some coastal U.S. refineries to go back to buying more expensive crude imports.

“If all older tankers were retrofitted, it could add between 20 and 40 cents per barrel to crude-by-rail costs, assuming a cost of $30,000 to $60,000 per car, according to a report this month from Turner, Mason & Company consultants.

“Should producers have to rely just on pipelines, Bakken deliveries would plummet to less than 600,000 bpd at the most, less than 60 percent of daily output, according to the state pipeline authority.

“Because of its rapid output growth and isolated location from fuel markets, only a small portion of Bakken crude is processed in facilities known as fractionation plants, which strip out volatile gases like propane and butane, known as light ends. The plants can require large up-front investment, and years to build.” (Whoa there, time and money again? Forget it!)

“‘Regulatory costs are going to go up, it’s just a question of how high and how fast,’ said Robert McNally, president at U.S. energy consultant Rapidan Group. ‘I expect officials will try to find a sweet spot where timely and adequate regulations … do not cripple Bakken economics.’” (Ah yes, a sweet spot that doesn’t interfere with profit!)

Just maybe in all of that there are some lessons for those of us living in Benicia, California about the priorities that should be guiding our decisions when it comes to bringing in Bakken and Canadian tar sands crude. Our neighbors to the east on that train route are obviously deeply concerned; why not Benicia?

Should an accident or major spill occur on that clearly precarious route down the Feather River Canyon, the damage to river, reservoir and water supply would be incalculable. And what of Sacramento and Davis and their obvious great vulnerability — have we no responsibility to our neighbors along that long trail from Alberta or North Dakota to Valero?

And, finally, of course, there is that bloody problem of the environmental costs of jacking up our use of not just more oil — bad enough in itself — but the most dangerously polluting stuff we can find. A bizarre example of man’s capacity to blot out the future in the pursuit of — just what?!

Jerome Page is a Benicia resident.