Mexico’s President Signs Energy Overhaul Into Law

Wall Street Journal

LATIN AMERICA NEWS

Mexico’s President Signs Energy Overhaul Into Law

Legislation Ends Monopoly of State-Owned Petróleos Mexicanos

By

JUAN MONTES
Dec. 20, 2013 3:06 p.m. ET
MEXICO CITY—Mexican President Enrique Peña Nieto signed into law Friday a bill that ends the monopoly of state-owned Petróleos Mexicanos in oil and gas, opening new horizons for private-sector investment in the world’s ninth-largest oil producer.

The energy bill, Mr. Peña Nieto’s wager to lift stagnant oil production and unleash economic growth, was passed by lawmakers in just 10 days. Congress gave final approval on Thursday of last week after two days of debates, and a required majority of state legislatures, 26 of the country’s 31, approved the constitutional amendment by this week.

“This year, we Mexicans have decided to overcome myths and taboos in order to take a large stride toward the future,” Mr. Peña Nieto said in a speech at the National Palace.

Mr. Peña Nieto became the first president in more than 50 years to propose and pass in Congress changes to the constitution on the subject of oil. The last one was Adolfo López Mateos in 1960, and that was to reinforce a state monopoly set up in 1938 when former President Lázaro Cárdenas expropriated the oil industry and turned oil into a nationalist symbol of Mexican sovereignty.

Under the changes, Mexico’s oil market will go from being run by a single player, state-firm Petróleos Mexicanos, or Pemex, to a competitive one in which private oil and gas firms will be allowed to explore for and produce hydrocarbons. Pemex will continue to be state-owned, with preferential rights to bid for oil blocks.

The process of implementing the law kicks off immediately. Pemex has three months to choose which of its existing exploration and production areas it wants to retain for itself and demonstrate that it has the capacity to exploit them. The Energy Ministry will have up to six months to approve Pemex’s choice.

The Energy Ministry will then launch the first bidding rounds for new areas of exploration for oil and gas, mainly in deep water and shale gas, which could happen in the last quarter of next year or in 2015.

The government will be able to become a partner with private firms in these new areas through different types of contracts, including licenses and deals to share the oil production. Pemex also will be able to award the new contracts, which go beyond the restrictive service contracts that the state firm always has used to farm out exploration and production work. Private firms will also be allowed to own and operate oil refineries.

The energy overhaul also liberalizes the generation, distribution and sale of electricity, opening up the state-owned utility CFE to direct competition.

The bill amends three key articles of the Mexican constitution—25, 27 and 28—which form the legal core of the country’s nationalistic oil laws. Constitutional changes are accompanied by several temporary dispositions detailing points that secondary legislation must contain. Congress has until the end of April pass the legislation.

Write to Juan Montes at juan.montes@wsj.com

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Case For Exporting Marcellus Shale Gas

Q&A: Industry Economist Makes the Case for Exports

JUNE 18, 2013 | 3:26 PM
BY 

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

ISSEI KATO / REUTERS/LANDOV

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

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

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

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

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

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

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

Q: Phillips: And why is that?

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

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

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

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

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

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

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

BOOM IN NATURAL GAS PRODUCTION SENDS U.S. SHIPYARDS INTO OVERDRIVE

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AP

Boom In Natural Gas Production Sends U.S. Shipyards Into Overdrive

The Great American Energy Boom is having a major ripple effect on the shipbuilding industry, which thanks to a 1920s maritime law, is busier than it has been in decades.

Some ten supertankers are currently under construction at U.S. shipyards, with orders for another 15 in the pipeline. That may not seem like a huge number, but considering there are only about 75 such tankers plying American ports now, it represents a genuine boat-building boom.

“We haven’t seen something like this since the 1970s,” Matthew Paxton, president of the Shipbuilders Council of America said to FoxNews.com. “The movement of more oil has built up a real commercial shipbuilding renaissance.”

The renaissance comes despite an economy that continues to struggle. It’s because of a specific sector of the U.S. economy that is also booming: natural gas production. The fuel must be transported, even within the country, either by rail, pipeline or ship. And if it is by ship, the ship must be American-made and American-manned, according to the 1920s Merchant Marine Act, also known as the Jones Act.

Paxton said that it is projected that up to 3.3 million barrels will be shipped out daily from the Gulf Coast by 2020, destined for ports along the east and west coasts, causing huge demand for tanker ships.

“It could be higher as more and more tankers are built,” he said.

With record amounts of gas and oil being extracted from shale by the process of fracking, the U.S. has seen an energy boom in recent years that has proponents calling it the Saudi Arabia of natural gas. Much of the fuel is being exported, but most is staying here, being distributed around the nation for domestic use.

Is Keystone Doomed To Be a Historical Footnote?

Is Keystone Doomed To Be a Historical Footnote?

By Ben Winkley Wall Street Journal

WHO NEEDS KEYSTONE, ANYWAY?

As 2013 rolls on from summer into fall there is still no end in sight to one of the great energy impasses of the year—will the Keystone XL pipeline ever be approved, or is it fated to become a historical footnote?

The pipe, in case you have forgotten, is planned to allow 830,000 barrels a day of heavy crude to move from Canada’s oil sands development all the way to refineries on America’s Gulf Coast.

Keystone needs approval from the State Department because it crosses the Canadian-U.S. border. The debate on whether it is a good idea or not has seemingly been endless and a decision may not now be made until 2014.

U.S. refiners increasingly doubt that Keystone will ever be built, The Wall Street Journal’s Ben Lefebvre reports. Only now, thanks to the expansion of other pipelines, the record amount of oil being produced in the U.S. and the rapid expansion of crude-by-rail, they don’t particularly care.

Which is all well and good for American refiners—and probably for these seven adorable species threatened by Keystone—but potentially ruinous for Canadian drillers.

Extracting Canada’s huge deposits of oil sands in the next few years might not be economically viable without Keystone XL. Oil-sands production capacity is predicted to more than double by 2030, to more than 5 million barrels a day—if Keystone doesn’t happen, output could exceed shipping capacity as soon as 2016.

This will mean that Canadian heavy crude will continue to trade at a steep discount to other grades of oil for the next few years, which could weigh on the economics of developing the oil sands.

So Canada hopes to build some pipes of its own—one all the way from Alberta to the Atlantic coast, and one to the Pacific. The former faces the challenge of scale; the latter of local opposition.

If Canada gets one or both of these off the ground, however, it could mean that Keystone turns out to be a lot of fuss over nothing. A lifeline could be thrown its way, though. The U.S. Federal Railroad Administration has begun an investigation into the business of moving hazardous materials—read: crude oil—on the tracks in light of the fatal accident in Quebec earlier in the year.

Any new safety measures or restrictions (say, on moving crude through residential areas) could increase the cost of moving oil-by-rail, and make that pipeline look a more attractive option once more.

INDIA BETWEEN A ROCK AND A HARD PLACE

India is considering a plan to reduce its ballooning current-account deficit that includes holding its oil imports from Iran steady, potentially putting the country in jeopardy of losing an exemption from U.S. sanctions against countries that do business with Iran.

The subcontinent is stuck between a rock and a hard place. Its currency, the rupee, has recently hit record lows against the U.S. dollar, making crude-oil imports much more expensive.

India imports more than three-quarters of the crude oil it requires, and the depreciating local currency would make those imports more expensive in rupee terms and add to the costs of government fuel subsidies.

India is turning to the Middle East, looking for deals. Oil exporters are eager to boost supplies to India to compensate for shrinking U.S. demand.

India and Iraq are working toward a 10-year oil-supply deal and the former may offer a stake in state-run India Oil Corp.’s planned refinery in the east of the country, the Journal’s Saurabh Chaturvedi and Biman Mukherji report.

Dealing with Iran will prove more contentious. India buys oil from the Islamic Republic by depositing rupees into a bank account, and then Iran imports Indian goods, potentially including food, drugs, consumer products and auto parts, debiting rupee amounts from the same account.

A bizarre ongoing dispute over an Indian oil tanker that was detained by Iran’s navy threatens to stall negotiations, but India may feel its need for fuel is greater than America’s need to squeeze Iran.

More U.S. oil is moving via truck, barge and train than at any point since 1981

COMMODITIES Updated August 26, 2013, 12:07 a.m. ET

Pipeline-Capacity Squeeze Reroutes Crude Oil

More U.S. oil is moving via truck, barge and train than at any point since 1981

By RUSSELL GOLD CONNECT

More crude oil is moving around the U.S. on trucks, barges and trains than at any point since the government began keeping records in 1981, as the energy industry devises ways to get around a pipeline-capacity shortage to take petroleum from new wells to refineries.

Getty Images

Oil container cars sit at a train depot outside Williston, N.D.

The improvised approach is creating opportunities for transportation companies even as it strains roads and regulators. And it is a precursor to what may be a larger change: the construction of more than $40 billion in oil pipelines now under way or planned for the next few years, according to energy adviser Wood Mackenzie.

“We are in effect re-plumbing the country,” says Curt Anastasio, chief executive of NuStar Energy LP, a pipeline company in San Antonio. Oil is “flowing in different directions and from new places.”

U.S. oil production has reached its highest level in two decades, while imports have fallen dramatically. A system built to import oil and deliver it to coastal refineries has become ill-equipped to handle rising production in Texas, North Dakota and Canada’s Alberta province.

“All of the pipes are pointed in the wrong direction,” says Harold York, an oil researcher at Wood Mackenzie. “We are turning the last 70 years of oil-industry history in North America on its head, and we are turning it on its head in the next 10 to 15 years.”

With oil prices persistently above $100 a barrel, companies drilling new wells don’t want to forgo revenue while they wait years for new pipelines. That leaves them with trucks, trains and barges to move an increasing amount of crude.

Oil delivered to refineries by trucks grew 38% from 2011 to 2012, according to the U.S. Energy Information Administration, while crude on barges grew 53% and rail deliveries quadrupled. Although alternatives are growing rapidly, pipelines and oceangoing tankers remain the primary method for delivering crude to refineries.

In the Eagle Ford, a large four-year-old South Texas oil field, production has grown to more than 500,000 barrels a day, from less than 1,000 in 2009, according to state statistics. Getting that torrent out of the sparsely populated region has required modifications to the oil-delivery system.

For example, last year NuStar reversed a 16-inch pipeline built to carry crude imported from Africa and Europe northward from the Port of Corpus Christi. Now, the pipeline flows south, taking delivery from hundreds of trucks that fill up at individual wells. Some of the 175,000 barrels a day moving through the pipe is loaded onto barges at Corpus Christi and towed toward refineries near Houston.

Earlier this year, Phillips 66 began putting some of this crude on ships for a 2,200-mile journey around Florida to its refinery in Linden, N.J.

The heavy trucks moving Eagle Ford crude are causing headaches for residents and local officials, ripping up roads and causing traffic tie-ups.

“These are rural roads built for 10 cars an hour, and now it’s 100 vehicles an hour, and 75 of them are 80,000-pound trucks,” says Tom Voelkel, president of Dupre Logistics LLC. The Lafayette, La., company started hauling crude in Eagle Ford in November 2011 and has more than 100 drivers full time in the region.

The Texas Legislature appropriated $450 million this year to repair and improve roads in oil-producing counties. “It doesn’t even begin to reach where it needs to reach,” says Daryl Fowler, the chief elected county official in Cuero, Texas, about a hundred miles southeast of San Antonio.

“We’ve seen a fourfold increase in congestion around here,” he says. “The roads are crumbling.”

In July, the Texas transportation department decided to convert 83 miles of state road in six oil-boom counties from pavement to gravel, to reduce repair costs and slow traffic.

Trucks filled with Eagle Ford crude are also heading 100 miles west to a barge canal. The first barge of crude departed in September 2011, heading south toward the Gulf of Mexico and refineries near Houston. Now the canal moves 1.6 million barrels a month, says Jennifer Stastny, executive director of the Port of Victoria.

“It’s like putting your 5-year-old to bed one night and he wakes up the next morning as a 16-year-old, with the appetite and demands of a 16-year-old,” she says.

In North Dakota, trains move 69% of the state’s 800,000 barrels a day of crude, according to state figures. Energy companies say they value rail’s ability to deliver crude to the highest-paying markets.

But the deadly runaway crude train crash in Canada’s Quebec province in July, which incinerated a small town and killed at least 47 people, highlighted the risks of the mile-long crude trains crisscrossing the country. The U.S. government is imposing new regulations on oil shipments by rail.

Some state regulators wonder if their local efforts leave them prepared for a train accident, in part because federal railroad rules pre-empt state and local control over trains.

In Washington state, “we can’t say [to train operators] you have to have oil-spill contingency plans in order to operate,” says Curt Hart, a spokesman for the state’s Department of Ecology. “We do that for oil tankers, barges, large commercial vessels and refineries.”

Home to five refineries, the state levies a per-barrel tax on crude delivered by tankers and barges, which pays for spill-response officials and inspectors. The tax doesn’t apply to rail shipments.

The American Association of Railroads says it is prepared for growing crude shipments because it has long carried hazardous cargoes. In 2008, major U.S. railroads carried 9,500 carloads of crude, the association says, and are on pace this year to carry 389,000.

Most industry analysts believe that while crude on trains will last, truck and barge traffic will decline once new pipelines come into service.

Environmental groups have criticized some pipeline projects, including the Keystone XL, meant to move Canadian oil to Gulf Coast refineries. The federal government is still studying the Keystone pipeline and has yet to issue needed permits.

Steve Kean, president and chief operating officer of Kinder Morgan Inc., one of several interrelated companies that own or operate 82,000 miles of North American pipeline, says government agencies thoroughly vet new projects.

Falling imports, infrastructure investments and increased manufacturing are just some of the benefits of newly abundant energy supplies, he says. “This has got to be one of the best things that has happened in our economy in the past 10 years. It is better than the iPad.”

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Coal at Risk as Global Lenders Drop Financing

Coal at Risk as Global Lenders Drop Financing on Climate

By Mark Drajem – Aug 6, 2013 10:56 AM ET

Tomohiro Ohsumi/Bloomberg

An employee stands in front of stockpiles of coal inside a storage yard at the Joban Joint Power Co. coal-fired power station in Iwaki City, Japan.

The world’s richest nations, moving to combat global warming, are cutting government support for new coal-burning power plants in developing countries, dealing a blow to the world’s dominant source of electricity.

Obama Unveils Climate Plan Focused on Power Plants 48:10

June 25 (Bloomberg) — U.S. President Barack Obama speaks about his plan to address climate change. Obama, speaking at Georgetown University in Washington, proposed a sweeping plan that sets goals to reduce carbon emissions and bolster renewable energy while also preparing the country for the impacts of a warming planet. (Source: Bloomberg)

Enlarge image Coal at Risk as Global Lenders Drop Financing on Climate

A coal-fired power station stands in the distance behind a disused coal dredger in the town center in Morwell, Australia, on July 25, 2013. Photographer: Carla

Gottgens/Bloomberg

First it was President Barack Obama pledging in June that the government would no longer finance overseas coal plants through the U.S. Export-Import Bank. Next it was the World Bank, then the European Investment Bank, dropping support for coal projects. Those banks have pumped more than $10 billion into such initiatives in the past five years.

“Drawing back means there is less capital for these projects,” Richard Caperton, managing director for energy at the Center for American Progress in Washington, said in an interview. “I don’t expect private capital to move in and fill the void, either, because there is a real risk that these plants will be turned off early.”

Demand for coal in developing nations has taken on increasing importance as the combination of stricter environmental regulations in the U.S., increasing deployment of subsidized renewable resources and a drop in the price of natural gas have pushed utilities to shutter coal plants.

Among the three government-backed lenders, the World Bank has provided $6.26 billion for coal-related projects over the past five years, according to data from Oil Change International. The Ex-Im bank provided more than $1.4 billion to two coal projects, one in South Africa and another in India.

Curb Investments

While the pull back is unlikely to have a direct impact on China, the world’s top user of coal, it could curb construction of new plants in countries such as South Africa and Vietnam and dampen new export markets for coal mined in the U.S., Indonesia or Australia by companies such as Peabody Energy Corp. (BTU) and Alpha Natural Resources Inc. (ANR)

“We’ve never seen a cascading sentiment that coal is not acceptable like we’re seeing happen right now,” Justin Guay, the head of the Sierra Club’s international climate program, said in an interview. “It’s a snowball running downhill.”

Environmental groups such as the Sierra Club are fighting coal plants and coal mines, because coal releases the most carbon dioxide per unit of energy of any major fuel source. Scientists say carbon emissions are to blame for warming Earth’s temperatures, increasing the number and severity of storms and melting polar ice.

Supporters of the fuel source say it’s a low-cost way for poor nations to provide light, refrigeration and air conditioning to their people.

‘Our Backs’

The move by lenders against coal turns “our backs on millions without electricity and chooses not to help them achieve a better standard of living,” said Nancy Gravatt, a spokeswoman for the National Mining Association in Washington, which represents producers such as Alpha and

Arch Coal Inc. (ACI)

Analysts are divided about long-term global coal demand.

The U.S. Energy Information Administration, in a July 25 report, projected world coal use would increase by a third — to more than 200 quadrillion British thermal units a year — by 2040 as developing nations boost its use.

The cut-back in the financing isn’t causing a reassessment of that outlook, said Greg Adams, the team leader for coal at EIA. “The capacity that is going to be affected is going to be limited,” he said.

Gregory Boyce, chief executive officer of Peabody, the largest U.S. coal producer, noted that German and Japanese coal use is climbing as they cut nuclear-power generation.

China, India

“China and India imports have risen year-to-date and are on a pace to increase 15 percent this year to new record levels as the trends to urbanize, industrialize and electrify continue,” Boyce said in a conference call with analysts on July 23.

Goldman Sachs Group Inc. offers a less buoyant outlook.

“We believe that thermal coal’s current position atop the fuel mix for global power generation will be gradually eroded,” Christian Lelong, an analyst at Goldman Sachs in Australia, said in a report on July 24. “Most thermal coal growth projects will struggle to earn a positive return.”

Coal is now used to generate 40 percent of the world’s electricity, and its use has grown more than 50 percent in the past decade, according to EIA. The U.S. is the world’s second-largest producer of coal, after China, followed by India, Australia and Indonesia. China is the world’s top importer of coal as well, followed by Japan, according to the World Coal Association.

1,200 Plants

According to an analysis by the World Resources Institute in Washington, 1,200 coal-fired plants are proposed globally, with more than three-quarters of those planned for India and China alone. If all are built, which WRI says is unlikely, that would add more than 80 percent to existing capacity.

China can finance its projects on its own, and India has only relied on export financing in a few cases. As a result, the recent changes are likely to impact other nations in Africa and Asia, which don’t have the same access to credit. Each group said in some instances it would still finance coal, and activists are worried about those exceptions.

“The implementation of all three of those initiatives is yet to be fleshed out,” Doug Norlen, the policy director of Pacific Environment, which is fighting these kinds of fossil-fuel projects, said in an interview. “These will be huge steps, if properly implemented.”

That implementation is still an open question.

Project Rejected

For example, as part of Obama’s climate action plan released on June 25, the U.S. pledged to end support of foreign coal-fired power plants, unless they are in the poorest nations or have expensive carbon-capture technology. The U.S. Export-Import Bank is only now developing the procedures to implement that policy, and its board will consider those changes in the coming weeks. The lender shot down a bid to finance a coal plant in Vietnam, its only pending application for coal, just three weeks after Obama’s announcement.

Norlen’s group and other environmentalists filed a lawsuit against the Export-Import Bank last week to try to block its financing of coal exports. That support is separate from the policy change Obama announced.

The European Investment Bank set an emission performance standard that would prevent lending to new coal-fired plants unless they also burn biomass. The European Bank for Reconstruction and Development is also under pressure to limit support.

Japan Support

Even after the World Bank said it would help nations transition from coal to natural gas or renewables, it’s still considering support for a coal project in Kosovo.

There’s also the possibility that other lenders, especially export-credit agencies from Japan or China, could step in and replace the World Bank, U.S. and Europe. Japan’s Bank for International Cooperation, its export financing body, has provided more than $10 billion in financing for overseas coal projects, more than any other individual nation, according to the WRI report.

And now China, which wants to export coal-plant technology, may ramp up support as well, said Ailun Yang, the author of the WRI report.

“It is a real concern” that “some of the funding gap for coal-fired plants would simply be filled by the Chinese banks,” she said.

To contact the reporter on this story: Mark Drajem in Washington at mdrajem@bloomberg.net

To contact the editor responsible for this story: Jon Morgan at jmorgan97@bloomberg.net

Texas’ Next Big Oil Rush (WSJ 6/23/13)

New pipelines are beginning to carry a glut of domestic crude from the middle of the country to Texas’s Gulf Coast, boosting the fortunes of the area’s big refineries and further fueling a decline in oil imports. Dan Strumpf reports.

New pipelines are beginning to carry a glut of domestic crude from the middle of the country to Texas’ Gulf Coast, boosting the fortunes of the area’s big refineries and further fueling a decline in oil imports.

Magellan Midstream Partners’ Longhorn pipeline began shipping oil from West Texas to Houston in April—the first of at least seven pipeline projects that could send as much as two million barrels a day from oil-saturated choke points in Oklahoma and the interior of Texas to the largest concentration of refineries in the country. But domestic oil production is at such a high level that the Gulf Coast refineries won’t be able to process all of the crude.

The pipelines, all set to come online by the end of next year, mark a new phase in the U.S. oil boom.

Hydraulic fracturing has pushed U.S. oil output to its highest level in 17 years, but without adequate pipelines, much of the crude has been trapped at storage facilities, including domestically produced light, sweet crude at the massive storage hub in Cushing, Okla.

Because that Oklahoma crude is relatively stranded, its price is depressed compared with prices of oil stored in other parts of the U.S. and in Europe. But with the new pipelines, as well as increased use of rail cars and barges to move crude, Cushing prices are expected to rebound.

Light, sweet crude at Cushing is now trading at a discount of about $6 a barrel from imported European Brent crude, but far less than the $20 discount in February. Goldman Sachs Group Inc. says the discount could narrow to $5 by the third quarter as more pipeline capacity becomes available.

Oil refineries like this one near Houston are expected to benefit from new pipelines carrying less-expensive crude from inland and Midwest sites.

Refiners on the Texas Gulf Coast, which process about a quarter of U.S. gasoline, are poised to be the beneficiaries of the new pipelines. They have been largely stuck paying for more-expensive imported crude, or paying extra transport costs to have the cheaper, stranded U.S. crude brought in on rail cars, which are generally more costly than pipelines.

Valero Energy Corp., Phillips 66 and Marathon Petroleum Corp., as well as Exxon Mobil Corp., which runs a major refinery in Baytown, Texas, all stand to gain.

Valero will realize profit margins of $12.80 per barrel from 2013 to 2017, compared with $10.50 in 2011 and 2012, estimates investment research firm Morningstar. Phillips 66’s margins are projected to grow to $13.50 per barrel, from $11.40.

Refineries in the Midwest, meanwhile, may see adverse consequences. They have benefited from the regional glut, buying the low-price crude but selling gasoline at the same prices as their coastal competitors. (The price at the gas pump in the U.S. is determined by the higher cost of imported crude.)

Investors are already betting that Midwestern refiners’ profit margins will fall. Shares for CVR Energy Inc., which produces fuel in Oklahoma and Kansas, fell 4.3% Monday as the West Texas crude-oil discount continued to deteriorate.

However, Texas refiners won’t be able to take full advantage of the influx of U.S. oil, most of which is of the variety known as light sweet. That is because many of those refineries were modified years ago to also deal with heavier crudes from Mexico, Venezuela and Saudi Arabia, preventing significant portions of their plants from refining light crude.

“It’s rare to find a refinery down there that can take the majority of its crude” from the U.S. supply of light, sweet oil, said Cowen Securities analyst Sam Margolin.

Some industry experts think the pipelines will simply ease the oil glut in Cushing and create one in the Houston area as U.S. crude pours into the area faster than refiners can process it.

Trying to sell the crude abroad instead won’t provide refiners a relief valve: U.S. law prohibits most crude exports, although refined products can be shipped overseas.

“We think the U.S. Gulf Coast gets saturated” with U.S. and Canadian crude once the pipelines are completed, said Greg Garland, CEO of Phillips 66, the independent refiner which spun off from ConocoPhillips last year. If that occurs, Mr. Garland said more crude will instead have to move to the East and West coasts by rail.

The arrival of more U.S. light, sweet crude on the Texas coast is displacing imports of similar crude from Nigeria and Angola, which dropped to their lowest levels in about a quarter of century last year, a concern that was aired at the most recent OPEC meeting in May.

The competition from the new light crude arriving in Houston could push down the prices paid by Gulf Coast refiners for Gulf of Mexico oil, said Alex Morris, energy analyst at Raymond James. But it is unlikely that deep-water production would be curtailed, he added, because onshore production is easier to shut off if prices go down.

Write to Alison Sider at alison.sider@dowjones.com, Dan Strumpf at daniel.strumpf@dowjones.com and Ben Lefebvre at ben.lefebvre@dowjones.com

A version of this article appeared June 25, 2013, on page B1 in the U.S. edition of The Wall Street Journal, with the headline: Texas’ Next Big Oil Rush.