Tag Archives: Gulf of Mexico

US eases crude oil export ban; allows trading with Mexico

Repost from Associated Press – The Big Story

US eases crude oil export ban; allows trading with Mexico

By Josh Lederman, Aug. 14, 2015 3:34 PM EDT

AssociatedPressEDGARTOWN, Mass. (AP) — The Obama administration approved limited crude oil trading with Mexico on Friday, further easing the longstanding U.S. ban on crude exports that has drawn consternation from Republicans and energy producers.

Mexico’s state-run oil company Petroleos Mexicanos, or Pemex, had sought to import about 100,000 barrels of light crude a day and proposed a deal last year in which Mexico would trade its own heavier crude for lighter U.S. crude. A major crude exporter for decades, Mexico has seen its oil production fall in recent years.

The license applications to be approved by the U.S. Commerce Department allow for the exchange of similar amounts of U.S. and Mexican crude, said a senior Obama administration official, who wasn’t authorized to comment by name and spoke on condition of anonymity. The official didn’t disclose whether all 100,000 barrels requested would be allowed.

While the Commerce Department simultaneously rejected other applications for crude exports that violated the ban, the move to allow trading with Mexico marked a significant shift and an additional sign that the Obama administration may be open to loosening the export ban. Exchanges of oil are one of a handful of exemptions permitted under the export ban put in place by Congress.

The export ban is a relic of the 1970s, after an OPEC oil embargo led to fuel rationing, high prices and iconic images of long lines of cars waiting to fuel up. But Republicans, including House Speaker John Boehner, have said those days are long gone, arguing that lifting the ban could make the U.S. an energy superpower and boost the economy.

Republicans from energy-producing states hailed the decision, as did trade groups representing the oil industry. Sen. Lisa Murkowski of Alaska, who has pushed for lifting the ban, called it a positive step but added that she would still push for full repeal “as quickly as possible.”

“Trade with Mexico is a long-overdue step that will benefit our economy and North American energy security, but we shouldn’t stop there,” said Louis Finkel, executive vice president of the American Petroleum Institute.

But environmental groups have opposed lifting the ban out of concern it would spur further drilling for crude oil in the U.S. Pemex’s proposal has also drawn criticism in Mexico, where residents are sensitive about the country’s falling oil production despite warnings from officials that Mexico could become a net importer if it doesn’t explore new oil reserves.

The move to trade crude with Mexico comes as the Obama administration weighs a long-delayed decision about whether to approve the Keystone XL pipeline. That proposed project would carry crude oil from Canada’s tar sands to refineries on the Texas Gulf Coast, so the influx of heavy crude from Mexico could play into a decision about whether the controversial pipeline is necessary.

Last month a Senate panel approved a bill championed by Murkowski that would lift the 40-year-old-ban — plus open more areas of the Arctic, Gulf of Mexico and the Atlantic Ocean to oil and gas exploration. No Democrats on the committee voted for the bill. The environmental group Oceana called it “a massive give-away to Big Oil.”

U.S. oil reserves continue rising, surpass 36 billion barrels for first time since 1975

Repost from U.S. Energy Information Administration – Today In Energy

U.S. oil reserves continue rising, surpass 36 billion barrels for first time since 1975

December 5, 2014

graph of U.S. crude oil and lease condensate proved reserves, as explained in the article text

Source: U.S. Energy Information Administration, U.S. Crude Oil and Natural Gas Proved Reserves

U.S. crude oil and lease condensate proved reserves rose for the fifth consecutive year in 2013, increasing by 9% from the 2012 level to 36.5 billion barrels, according to the U.S. Crude Oil and Natural Gas Proved Reserves, 2013 report released yesterday by the U.S. Energy Information Administration (EIA). U.S. crude oil and lease condensate proved reserves surpassed 36 billion barrels for the first time since 1975.

Proved reserves

Proved reserves are those volumes of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

North Dakota had the largest increase (1.9 billion barrels, 51%) in oil reserves among individual states in 2013, based on development of the Bakken/Three Forks formation in the Williston Basin. With 5.7 billion barrels of proved reserves, North Dakota has more reserves than the federal offshore waters of the Gulf of Mexico. Texas remains by far the leading state in total proved oil reserves—its reserves increased from 11.1 billion barrels in 2012 to 12 billion barrels in 2013 (an 8% increase). The largest decline of 2013 was in Alaska, where proved reserves decreased by 454 million barrels, due mainly to reduced well performance at large existing oil fields.

map of changes in oil and lease condensate proved reserves by state/area, as explained in the article text

Source: U.S. Energy Information Administration, U.S. Crude Oil and Natural Gas Proved Reserves
Note: * data withheld to avoid disclosure of individual company data

Changes in reserves reflect exploration and development activities as well as financial factors. Increases in crude oil and lease condensate reserves in 2013 were mainly attributable to nearly 5 billion barrels of extensions to existing fields. Extensions are the result of additional drilling and exploration in previously discovered reservoirs, and have accounted for the majority of reserves increases over the past three years. Continued development of the Bakken/Three Forks play in North Dakota accounted for a large portion of the reserves additions, and overall, tight oil plays accounted for almost 30% of all U.S. crude oil and lease condensate proved reserves.

graph of components of crude oil and lease condensate reserve changes, as explained in the article text

Source: U.S. Energy Information Administration, U.S. Crude Oil and Natural Gas Proved Reserves

EIA’s estimates of proved reserves are based on an annual survey of domestic oil and gas well operators. For more information, read the full U.S. Crude Oil and Natural Gas Proved Reserves, 2013 report.

The Destructive Legacy of Tar Sands Oil

Repost from Co.Exist
[Editor: Great photos, best viewed on Co.Exist.  Also of interest on Co.Exist: This Is What Your City Would Look Like If All The World’s Ice Sheets Melt– RS]

As The Keystone Pipeline Inches Closer, Look At The Destructive Legacy Of Tar Sands Oil

A bird’s-eye view of the post-apocalyptic landscape that we’ve already created.
By Adele Peters, November 24, 2014 
Pine Bend Refinery, Rosemont, MN
Strips mines cover an area of forest seven times larger than Manhattan. Uncovered rail cars Loading Petroleum Coke, a byproduct of tar sands refining, Pine Bend Refinery, Rosemont, MN

By a single vote, the U.S. Senate failed to fast-track the approval of the controversial Keystone XL pipeline last week, which would carry Canadian tar sands oil straight across the nation to the Gulf of Mexico. Lawmakers are expected to approve it in January, however, and President Obama may or may not let it squeak through.

A new photo series traces the path of the proposed pipeline, from the tar sands in Alberta to massive refineries in Texas. The photos make something clear: With or without the pipeline, huge amounts of tar sands oil are already being extracted and flowing into the U.S. Over the last four years, the amount of Canadian crude sent to Texas has increased by 83%.

Photographer Alex MacLean first flew over Alberta last winter, taking shots of a post-apocalyptic landscape that are hard to capture from the ground.

Meandering Channel of Wastewater, Suncor Mine, Alberta, Canada

Strip mines cover an area of forest seven times larger than Manhattan. Since most of the tar sands are buried deep underground, and the molasses-like bitumen is too thick to extract on its own, the oil companies have also built enormous boilers to liquefy the sludge.

“Looking at the pictures of the huge furnaces they have to use in the wells, you can see how much energy this takes to extract,” says MacLean. “If you’re driving around with this fuel, it’s 17% to 20% more carbon intense than regular gas.”

MacLean returned to the oil fields again last summer with journalist Daniel Grossman, and then traveled on to refineries in the Midwest and the Gulf Coast that are already processing tar sands oil.

The Alberta Clipper line ships 450,000 barrels of oil to Wisconsin every day. One branch splits off to Detroit, where a refinery caused a three-day long oil spill in a river in 2010.

Steam and smoke rise from upgrading facility at Syncrude Mildred Lake Mine, Alberta, Canada

“That was a billion-dollar cleanup,” says MacLean. “It was totally overshadowed—they call it the oil spill no one ever heard of, because it happened almost simultaneously with the BP spill in the Gulf.”

Enbridge, the company responsible for that spill, managed to avoid a lengthy approval process to increase its capacity; by next year, it expects to ship 800,000 barrels of oil per day. Unlike the well-publicized Keystone project, it didn’t need a new permit, but instead connected two parallel pipelines running along the border. MacLean’s photos show new lines under construction.

In the Gulf, the photos show the refineries that Keystone may eventually connect to Alberta.

“The size of the capital investment is just staggering—hundreds of billions of dollars of refining infrastructure along the coast,” MacLean says. “It’s just incredible amounts of money. You realize that the pipeline, which is around $4 billion, is just small change in the scheme of things. They can spend hundreds of millions of dollars lobbying to get the pipeline through.”

MacLean hopes the photos help us better understand the impact of a possible approval.

“I think if we’re really going to seriously mitigate climate change, we really need to start now and not put in infrastructure that’s going to last 30 years,” he says. “We’d be saddled with these type of investments, when we’d be better off putting both our know-how and our money towards more sustainable resources.”

[By Adele Peters.   Adele Peters is a writer who focuses on sustainability and design and lives in Oakland, California. She’s worked with GOOD, BioLite, and the Sustainable Products and Solutions program at UC Berkeley.  All photos: Alex MacLean]

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.”