Tag 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.”

Oil Industry, Oil prices, Valero Energy Corporation

Global oil market: demand for road fuels has peaked and is now falling

Repost from The Economist
[Editor: An interesting European perspective on the future of world oil production and sales.  Note references to Valero near the end.  – RS]

A fuel’s errand

Making the most of a difficult business

| RUNCORN

THE sprawling acres of pipes, towers and tanks, which smash and rebuild hydrocarbon chains to turn crude oil into petrol, diesel and other useful stuff are vast and complicated. But the impressive scale of oil refineries is not matched by their profits. Refining in Britain is a miserable business these days.

In the 1960s big oil companies were so sure that demand for petrol would rise forever that they built the refineries to match. But demand for road fuels has peaked and is now falling—by 8% between 2007 and 2011. High fuel prices and stalling sales of vehicles that are anyway far more efficient are to blame. The result is wafer-thin margins and closures. Since 2009 two British refineries, at Coryton in Essex and in Teesside, have shut down. All but one of the remaining seven has been sold or been put up for sale in recent years.

Refineries operate in a global market. Petrol and diesel can be sent by tanker around the globe as readily as crude. Competing with sparkly, super-efficient new refineries in Asia and the Middle East is hard. Moreover, Britain’s older refineries were designed to produce petrol, which is increasingly the wrong fuel. Petrol sales by volume fell by 34% in the decade to 2011 while diesel grew by 73%. Around 40% of diesel is now imported. Nor do British refineries produce enough kerosene, which powers passenger jets, to supply the home market.

Big oil firms have sold up, preferring to invest in exploration and production. But why was anyone buying? For one thing, refineries are going cheap. Shell sold Stanlow to Essar Oil, an Indian firm, in 2011 for $350m (then £220m). In the same year Valero, an American refiner, bought Pembroke from Chevron for $730m.

The efforts to squeeze more returns from Stanlow show how refining can pay. Independent refiners like Essar and Valero are prepared to spend more time and money than big oil firms. Expertise and investment has put Stanlow, a 75m barrels-a-year refinery, well on the way in its plan to improve margins by $3 a barrel by 2014.

Essar aims to make Stanlow at least break even in bad times (in 2011 two-thirds of European refineries were losing money) and make decent profits when conditions improve. Generating energy using gas and tweaking technology to take crude from sources other than the North Sea, at better prices, is helping. Stanlow also has some natural advantages. It is the only refinery in the north-west and the closest to Liverpool, Manchester and Birmingham. Though refined fuel can be moved by pipeline, some 55% of the refinery’s output goes “off the rack”, loaded into road tankers to feed a big local market. More distant refineries, with higher transport costs, would have trouble competing.

But the market for fuel is still shrinking and tiny margins mean profits can be wiped out by small shifts in the price of crude or other costs. In the past five years Europe has lost 2.2m barrels a day (b/d) of refining capacity. Volker Schultz, Essar Oil’s boss in Britain, reckons that another 1m b/d needs to go. But that is not his only concern. Efforts in Britain to introduce a carbon floor-price will put its refineries at a disadvantage to European ones, and European environmental legislation will make the whole continent’s refineries even less competitive. It must seem to the industry as if it has a large hole in its tank and a small patch to fix it.

 

Bakken Crude, California Regulation, Crude By Rail, Derailment, Emergency Readiness & Response, Explosion, Federal Regulation (U.S.), Hazardous cargo transparency, Tank car design, Train speed

Bakersfield High School worst-case derailment scenario

Repost from the Bakersfield Californian
[Editor: this is a MUST READ article, a comprehensive and graphic description of first-responder requirements and readiness.  Someone needs to interview first responders in each of our Bay Area refinery towns, ask every single question referenced in this article, and lay out similar scenarios for the all-too-imaginable catastrophes that threaten our communities.  – RS]

Increased oil train traffic raises potential for safety challenges

By John Cox, Californian staff writer  |  May 17, 2014
Bakersfield High School is seen in the background behind the rail cars that go through town as viewed from the overpass on Oak Street. By Casey Christie / The Californian
Bakersfield High School is seen in the background behind the rail cars that go through town as viewed from the overpass on Oak Street. By Casey Christie / The Californian

First responders think of the rail yard by Bakersfield High School when they envision the worst-case scenario in Kern County’s drive to become a major destination for Midwestern oil trains.  If a derailment there punctures and ignites a string of tank cars, the fireball’s heat will be felt a mile away and flames will be a hundred feet high. Thick acrid black smoke will cover an area from downtown to Valley Plaza mall. Burning oil will flow through storm drains and sewers, possibly shooting flames up through manholes.

Some 3,000 BHS students and staff would have to be evacuated immediately. Depending on how many tank cars ignite, whole neighborhoods may have to be cleared, including patients and employees at 194-bed Mercy Hospital.  State and county fire officials say local 911 call centers will be inundated, and overtaxed city and county firefighters, police and emergency medical services will have to call for help from neighboring counties and state agencies.

While the potential for such an accident has sparked urgency around the state and the country, it has attracted little notice locally — despite two ongoing oil car offloading projects that would push Kern from its current average of receiving a single mile-long oil train delivery about once a month, to one every six hours.

One project is Dallas-based Alon USA Energy Inc.’s proposed oil car offloading facility at the company’s Rosedale Highway refinery. The other is being developed near Taft by Plains All American Pipeline LP, based in Houston.

Kern’s two projects, and three others proposed around the state, would greatly reduce California’s thirst for foreign crude. State energy officials say the five projects should increase the amount of crude California gets by rail from less than 1 percent of the state’s supply last year to nearly a quarter by 2016.

But officials who have studied the BHS derailment scenario say more time and money should be invested in coordinated drills and additional equipment to prepare for what could be a uniquely difficult and potentially disastrous oil accident.

Bakersfield High Principal David Reese met late last year with representatives of Alon, which hopes to start bringing mile-long “unit trains” — two per day — through the rail yard near campus.

He said Alon’s people told him about plans for double-lined tank cars and other safety measures “to make me feel better” about the project. But he still worries.

“I told them, ‘You may assure me but I continue to be concerned about the safety of my students and staff with any new (rail) project that comes within the vicinity of the school,'” he said.

Alon declined to comment for this story.

Both projects aim to capitalize on the current price difference between light crude on the global market and Bakken Shale oil found in and around North Dakota. Thanks to the nation’s shale boom, the Midwest’s ability to produce oil has outpaced its capacity to transport it cheaper and more safely by pipeline. The resulting overabundance has depressed prices and prompted more train shipments.

There are no oil pipelines over the Rockies; rail is the next best mode of shipping oil to the West Coast. Kern County is viewed as an ideal place for offloading crude because of its oil infrastructure and experience with energy projects. Two facilities are proposed in Northern California, in Benicia and Pittsburg; [emphasis added] the other would be to the south, in Wilmington.

A local refinery, Kern Oil & Refining Co., has accepted Bakken oil at its East Panama Lane plant since at least 2012. The California Energy Commission says Kern Oil receives one unit train every four to six weeks.

NATIONAL CHANGES

Shipments of Bakken present special safety concerns. The oil has been found to be highly volatile, and the common mode of transporting it — in quick-loading trains of 100 or more cars carrying more than 3 million gallons per shipment — rules out the traditional safety practice of placing an inert car as a buffer between two containing dangerous materials.

The dangers of shipping Bakken crude by unit train have been evident in several fiery derailments over the past year. One in July in Lac-Megantic, Quebec, Canada, killed 47 people and destroyed 30 buildings when a 74-car runaway train jumped the tracks at 63 mph.

The U.S. Department of Transportation said 99.9 percent of U.S. oil rail cars reached their destination without incident last year. Two of its divisions, the Federal Railroad Administration and the Pipeline and Hazardous Materials Safety Administration, have issued emergency orders, safety advisories and special inspections relating to oil car shipments. New rules on tank car standards and operational controls for “high-hazard flammable trains” are in the federal pipeline.

Locally operating companies Union Pacific Railroad Co. and BNSF Railway Co. signed an agreement with the DOT to voluntarily lower train speeds, have more frequent inspections, make new investments in brake technology and conduct additional first-responder training.

Until new federal rules take effect next year, railroads can only urge their customers to use tank cars meeting the higher standards.

“UP does not choose the tank car,” Union Pacific spokesman Aaron Hunt wrote in an email. “We encourage our shippers to retrofit or phase out older cars.”

The San Joaquin Valley Railroad Co., owned by Connecticut-based Genesee & Wyoming Inc., is a short line that carries Kern Oil’s oil shipments and would serve the Plains project but not Alon’s. A spokesman said SJVR is working with the larger railroads to upgrade its line, and the company inspects tracks ahead of every unit train arrival, among other measures designed just for oil shipments.

STATE LEVEL PROPOSALS

Gov. Jerry Brown has proposed a big change in the way California protects against and responds to oil spills.

His 2014-15 budget calls for $6.7 million in new spending on the state’s Oil Spill Prevention and Administration Fund to add 38 inland positions, a 15 percent staffing increase. Currently the agency focuses on ocean shipments, which have been the norm for out-of-state oil deliveries in California.

To help pay for the expansion, Brown wants to expand a 6.5 cent-per-barrel fee to not only marine terminals but all oil headed for California refineries.

“We’ll have a more robust response capability,” said Thomas Cullen, an administrator at the Office of Spill Prevention and Response, which is within the state Department of Fish and Wildlife.

A representative of the oil trade group Western States Petroleum Association criticized the proposal March 19 at a legislative joint hearing in Sacramento. Lobbyist Ed Manning said OSPR lacks inland reach, and that giving such responsibilities to an agency with primarily marine experience “doesn’t really respond to the problem.”

WSPA President Catherine Reheis-Boyd has emphasized the group has not taken a position on Brown’s OSPR proposal.

Also at the state capitol, Assemblyman Roger Dickinson, D-Sacramento, has forwarded legislation requiring railroads to give first responders more information about incoming oil shipments and publicly share spill contingency plans. The bill, AB 380, would also direct state grants toward local contingency planning and training. It is pending before the Senate Environmental Quality Committee.

LOCAL PREPARATIONS

In recent years Kern County has conducted large-scale, multi-agency emergency drills to prepare for an earthquake, disease outbreak and Isabella Dam break. There has not been a single oil spill drill.

Emergency service officials say that’s not as bad as it sounds because disasters share common actions — notification, evacuation, decontamination.

Nevertheless, State Fire and Rescue Chief Kim Zagaris, County Fire Chief Brian Marshall and Kern Emergency Services Manager Georgianna Armstrong support the idea of local oil spill drills involving public safety agencies, hospitals and others.

Kern County is well-versed at handling hazardous materials. Some local officials say an oil accident may actually be less dangerous than the release of toxic chemicals, which also travel through the county on a regular basis.

There have been recent accidents, but all were relatively minor.

Federal records list 18 oil or other hazardous material spills on Kern County railroads in the last 10 years. No one was injured; together the accidents caused $752,000 in property damage.

Most involved chemicals such as sodium hydroxide and hydrochloric acid. Only two resulted in crude oil spills, both in 2013 in the 93305 ZIP code in the city of Bakersfield. Together they spilled a little more than a gallon of oil.

But the risk of spills rises significantly as the volume of oil passing through the county grows.

“The volume is a big deal,” Bakersfield Fire Chief Douglas R. Greener said. “Potentially, if you have a train derail, you could see numerous cars of the same type of material leaking all at once.”

Kern County firefighters are better prepared for an oil spill than many other first responders around the state. They train on an actual oil tanker and have special tools to mend rail car punctures and gashes. The county fire department has several trucks carrying spray foam that suffocates industrial fires.

But Chief Marshall acknowledged a bad rail accident could strain the department’s resources.

He has been speaking with Alon about securing additional firefighting equipment and foam to ensure an appropriate response to any oil train derailment related to the company’s proposed offloading facility.

What comes of those talks is expected to be included in an upcoming environmental review of the project.

“We recognize the need to increase our industrial firefighting program,” Marshall said.

Chief Zagaris said Kern’s proximity to on-call emergency agencies in Tulare, Kings and Los Angeles counties may come in handy under the Bakersfield High spill scenario, which is based on fire officials’ assessments and reports from several similar incidents over the past year.

He and Marshall would not estimate how many people would require evacuation in the event of a disaster near the school, or what specific levels of emergency response might become necessary.

But Zagaris said local public safety officials would almost certainly require outside help to assess injuries, transfer people in need of medical care, secure the city and contain the spill itself.

“I look at it as, you know, depending what it is and where it happens will dictate how quickly” outside resources would have to be pulled in, he said.

For safe and healthy communities…